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GEOKINETICS INC. FORM 10-K FOR THE FISCAL YEAR ENDED DECEMBER 31, 2009 TABLE OF CONTENTS
TABLE OF CONTENTS CONSOLIDATED FINANCIAL STATEMENTS

Table of Contents

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-K

Commission file number: 001-33460

GEOKINETICS INC.
(Exact name of registrant as specified in its charter)

(Telephone Number) (713) 850-7600

         Securities registered pursuant to Section 12(b) of the Act:

         Securities registered pursuant to Section 12(g) of the Act: None

         Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o    No ý

         Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes o    No ý

         Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý    No o

         Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý    No o

         Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ý

         Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):

         Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o    No ý

         State the aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant.

         Aggregate market value of the common stock held by non-affiliates of the registrant as of June 30, 2009, computed by reference to the closing sale price of the registrant's common stock on the NYSE AMEX on such date: $61.8 million.

         Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date.

         Common Stock, par value $0.01 per share. Shares outstanding on March 12, 2010: 17,657,655 shares

Documents Incorporated by Reference

         Portions of the definitive proxy statement for the Registrant's Annual Meeting of Stockholders to be held on April 27, 2010, which the Registrant expects to file with the Securities and Exchange Commission within 120 days after December 31, 2009, are incorporated by reference into Part III of this report.

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GEOKINETICS INC.

FORM 10-K

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2009

TABLE OF CONTENTS

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PART I

Item 1.    Business

        Unless the context otherwise requires, references in this annual report to "the company," "our company," "the registrant," "we," "our," "us," and "Geokinetics" shall mean Geokinetics Inc. and its consolidated subsidiaries. References in this annual report to "PGS Onshore", "Grant" or "Trace" refer to certain entities and assets formerly comprising the onshore seismic business of Petroleum Geo-Services ASA, to Grant Geophysical, Inc. and its subsidiaries and to Geokinetics Exploration Inc. (formerly known as Trace Energy Services Ltd.) and its subsidiaries, respectively. References to the Trace acquisition refer to the Company's acquisition of Trace and the related financing of that acquisition which closed in December 2005. References to the Grant acquisition refer to the Company's acquisition of Grant and the related senior loan and subordinated loan used to finance that acquisition which closed in September 2006. References to the PGS Onshore acquisition refer to the Company's acquisition of PGS Onshore, which closed in February 2010, and the related financing of that acquisition.

Forward Looking Statements

        This report contains forward-looking statements that involve risks and uncertainties. These forward-looking statements are often accompanied by words such as "believe," "should," "anticipate," "plan," "expect," "potential," "scheduled," "estimate," "intend," "seek," "goal," "may" and similar expressions. These statements include, without limitation, statements about our acquisition of the onshore seismic data acquisition and multi-client data library business of Petroleum Geo-Services ASA ("PGS Onshore"), our market opportunity, our growth strategy, competition, expected activities, future acquisitions and investments, and the adequacy of our available cash resources. We urge you to read these statements carefully and caution you that matters subject to forward-looking statements involve risks and uncertainties, including economic, regulatory, competitive and other factors that may affect our business. These statements are not guarantees of future performance and are subject to risks, uncertainties and assumptions. Although we believe that the expectations reflected in the forward-looking statements are reasonable, we cannot guarantee future results, levels of activity, performance, or achievements. Moreover, we do not assume any responsibility for the accuracy and completeness of such statements in the future.

        Forward-looking statements involve known and unknown risks and uncertainties that may cause our actual results in future periods to differ materially from those projected or contemplated in the forward-looking statements as a result of, but not limited to, the following factors:

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our ability to successfully value PGS Onshore and to integrate it into our existing operations;



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a decline in capital expenditures by oil and gas exploration and production companies;



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market developments affecting, and other changes in, the demand for seismic data and related services;



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the timing and extent of changes in the price of oil and gas;



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our future capital requirements and availability of financing on satisfactory terms;



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availability or increases in the price of seismic equipment;



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availability of crew personnel and technical personnel;



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competition;



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technological obsolescence of our seismic data acquisition equipment;



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the condition of the capital markets generally, which will be affected by interest rates, foreign currency fluctuations and general economic conditions;

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•

the effects of weather or other delays on our operations;



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cost and other effects of legal proceedings, settlements, investigations and claims, including liabilities which may not be covered by indemnity or insurance;



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governmental regulation; and



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the political and economic climate in the foreign or domestic jurisdictions in which we conduct business.

        We have also discussed the risks to our business under the caption "Risk Factors" disclosed under Item1A. Given these risks and uncertainties, we can give no assurances that results projected in any forward-looking statements will in fact occur and therefore caution investors not to place undue reliance on them. We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as required by law. In light of these risks, uncertainties and assumptions, the forward-looking events discussed in this report and the documents incorporated by reference herein might not occur.

Our Business

        We are a full-service, global provider of seismic data acquisition, multi-client data library and seismic data processing and interpretation services to the oil and natural gas industry. As an acknowledged industry leader in land, marsh, swamp, transition zone and shallow water (up to 500 feet water depths) ocean bottom cable or "OBC" environments, we have the capacity to operate up to 38 seismic crews with approximately 206,000 recording channels worldwide and the ability to process seismic data collected throughout the world. Crew count, configuration and location can change depending upon industry demand and requirements.

        We provide a suite of geophysical services including acquisition of two-dimensional ("2D"), three-dimensional ("3D"), and multi-component seismic data surveys, data processing and interpretation services and other geophysical services for customers in the oil and natural gas industry, which include many national oil companies, major international oil companies and smaller independent oil and gas exploration and production companies (collectively "E&P Companies") in the Gulf Coast, Mid-Continent, California, Appalachian and Rocky Mountain regions of the United States, Western Canada, Canadian Arctic, Latin America, Africa, the Middle East, Australia/New Zealand and the Far East. Seismic data is used by E&P companies to identify and analyze drilling prospects, maximize drilling success, optimize field development and enhance production economics. We also maintain a multi-client data library whereby we maintain full or partial ownership of data acquired for future licensing. Our multi-client data library consists of data covering various areas in the United States and Canada. For the years ended December 31, 2009, 2008 and 2007, we generated total revenues of $511.0 million, $474.6 million and $357.7 million, respectively.

Our Strengths

        Leading provider with a balanced global market presence.    Our global diversity and exposure to both oil and natural gas reserve opportunities provide us with a balanced market presence, which increases new contract opportunities while reducing our sensitivity to individual markets and commodity price volatility. We have the equipment and trained personnel to deploy up to 38 seismic crews throughout the world. Our size and operating capability allow for improved crew and equipment utilization and the ability to service our customers across the globe. Our long operating history and reputation for quality service encourages customers to continue to select us as their provider of seismic data acquisition services.

        Specialized expertise in difficult environments and key high-growth markets.    We specialize in seismic data acquisition services in transition zones and other difficult land environments, which we believe to

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be underserved and one of the fastest growing segments of the overall seismic services industry. Additionally, we recently entered the Ocean Bottom Cable, or "OBC," market with one active crew and were the first operators of Sercel's SeaRay system. The Company's extensive experience operating in such complex and challenging areas, including its expertise in designing and utilizing special equipment customized for these environments, provides us a significant competitive advantage. We also have experience operating in local markets within key high growth regions around the world, such as Latin America, the Middle East and the Far East. We have been operating in the Far East longer than many of our major competitors. In addition, the expertise required to operate in these areas and the difficult nature of the work positions us to potentially realize higher operating margins than we realize on more traditional land seismic projects.

        Strong relationships with a globally diversified customer base.    We have strong, long-standing relationships with a diverse customer base consisting of national oil companies, super majors, majors and E&P Companies in over 30 countries. We have been providing seismic data acquisition services to many of our largest customers for over five years. Our global operating capability and sizable crew count allow us to leverage relationships with our customers and increase revenues by providing them services throughout the world and tailoring crew sizes to meet their requirements. Our customer base is diversified and it is not dependent on any one customer. For the year ended December 31, 2009, no single customer accounted for more than 20% of our total revenues.

        Strong backlog that provides significant revenue visibility.    Even though the oil and gas business entered into a period of reduced spending on exploration and development due to the recent economic recession and other factors, our backlog continues to remain strong. The strength of our backlog is due to our recent acquisition of PGS Onshore and to our strong relationships with national oil companies whose capital budgets are less dependent on commodity prices than many of the independent exploration and production companies. We estimate our total seismic data acquisition and seismic data processing revenue backlog to be $190.2 million as of December 31, 2009 of which $30.0 million are North American projects and $160.2 million are international projects. On a pro-forma basis with PGS Onshore, which we acquired on February 12, 2010, total backlog was $378.2 million as of December 31, 2009 of which $89.0 million are North American projects and $289.2 million are international projects.

        Multi-client library.    The acquisition of PGS Onshore significantly increased our multi-client library portfolio. PGS Onshore invested $133.1 million during 2008 and 2007 developing a 5,500 square mile multi-client library focused on high impact drilling areas or areas of high lease turnover in Texas, Oklahoma, Alaska and Wyoming. We believe this library is of high quality. This portfolio together with our recent entry into the multi-client library business provides opportunities for growth as drilling activity begins to pick up and as E&P companies look to drill wells in advance of lease expiration. We believe there are significant opportunities in North America, including the shale plays, for the continued expansion of our multi-client library business. As we grow our multi-client portfolio, we plan to secure a significant portion of prefunded sales prior to commencing any multi-client project.

        Highly experienced management team and strategic equity investors.    We draw on the global experience of our management team to maintain our leading market position and strong customer relationships. Our senior executive management team has an average of over 20 years of relevant industry experience in the seismic services sector as well as in oil and gas exploration, with a demonstrated track record. Our largest shareholder is Avista Capital Partners, L.P. or "Avista" and its respective affiliates, which initially invested in us at the time of our merger with Grant Geophysical in 2006. Avista brings significant experience as an investor in the oilfield service sector. Our second largest shareholder is, as a result of the acquisition of PGS Onshore, Petroleum Geo-Services ASA, a leading geophysical services provider with deep industry knowledge.

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Our Strategy

        Maintain focus and specialization in profitable, high-potential markets.    To maximize profitability, we will continue to target our growth in areas in which we believe we have a competitive advantage, such as transition zones and other difficult land environments, as well as OBC operations. We believe these areas continue to be underserved and represent one of the fastest growing segments of the overall seismic services market. We also plan to further expand our presence, both geographically and in the types of services offered, in existing and new high-potential markets throughout the world to diversify our customer base and capitalize on opportunities in our areas of operations.

        Prudently invest in new and technologically-advanced equipment.    The Company believes growth in demand for seismic services will continue to be enhanced by the development and application of new technologies, particularly for use in difficult land environments and transition zones. We will continue to acquire and develop expertise in utilizing technologically-advanced equipment to perform its services. In addition, we have upgraded and will continue to upgrade our existing equipment, primarily for our transition zone and OBC operations, to improve operating efficiency and to equip us for larger crew sizes, which we expect to lead to increased operating margins.

        Make strategic investments in our multi-client data library.    We believe that opportunities exist for us to continue to build and expand our multi-client data library in areas that will provide a high likelihood for future revenues. We will continue to acquire data for our own account with a particular near-term focus on the shale plays in the United States.

        Provide a broad range of services.    We believe there are significant global opportunities in providing customers a broad range of seismic data services, from acquisition and processing to interpretation and management and partnering with E&P companies for multi-client library projects. Customers are increasingly seeking integrated solutions to better evaluate known oil and gas deposits and improve the amount of recoverable hydrocarbons. Given our size and technological capabilities, we believe we have the infrastructure to significantly expand these multiple service offerings that add value and efficiency for our customers.

        Enhance asset utilization and operating efficiency.    Through greater customer and geographic diversification, upgraded equipment and improved crew capabilities, we seek to enhance the continuity of our seismic crews, the utilization of our equipment and our operating efficiency, which we expect will generate increased revenues and higher margins. Expanding our customer base and presence internationally will allow us to better manage our resources and minimize our reliance on certain customers, downtime between projects and the effects of seasonality and cyclicality in our business. In addition, we believe that the PGS Onshore acquisition will result in recurring and annual synergies through rationalizing office locations, the elimination of duplicate corporate functions, and improved purchasing power. We also believe there will be additional cross-selling opportunities to enhance revenue.

        Actively pursue strategic acquisitions.    We intend to pursue growth through strategic acquisitions. We seek to identify and complete acquisitions that will enhance our cash flow, complement our products and services, improve our operating efficiency, expand our geographic footprint and presence in key high-growth markets and further diversify our customer base.

Recent Developments

The PGS Onshore Acquisition

        On December 3, 2009, we agreed with Petroleum Geo-Services ASA and certain of its subsidiaries ("PGS") to acquire PGS Onshore. We closed this transaction on February 12, 2010. PGS Onshore has the ability to deploy 13 seismic crews, nine of which were active as of December 31, 2009, with over

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84,000 recording channels. The PGS Onshore acquisition is expected to provide us a significant business expansion into Mexico, North Africa, the Far East and the United States, including Alaska. As a result of the PGS Onshore acquisition, we acquired a seismic data library covering 5,500 square miles located primarily in Texas, Oklahoma, Alaska and Wyoming.

        We have leased seismic data acquisition, processing, maintenance, office and warehouse facilities in the United States, Angola, Australia, Bangladesh, Bolivia, Brazil, Colombia, Canada, Ecuador, Egypt, Indonesia, Libya, Mexico, Mozambique, Peru, Singapore, the Republic of Trinidad and Tobago, Tunisia, the United Arab Emirates, and Venezuela, which includes facilities obtained in the PGS Onshore acquisition.

        The following table provides information on Geokinetics and PGS Onshore's historical operations, and our operations on a pro forma basis assuming the consummation of the PGS Onshore acquisition as of December 31, 2009.

        The purchase price paid by Geokinetics at closing was $202.8 million, consisting of $183.4 million in cash and 2.15 million shares of Geokinetics common stock issued to PGS, including a working capital adjustment, calculated as follows (in millions):

        The purchase price is subject to certain additional working capital adjustments after closing. In addition, in connection with the acquisition, we agreed to reimburse PGS for certain costs incurred through the acquisition date related to two ongoing multi-client data library projects subject to certain requirements being met. We estimated this amount to be $2.0 million at closing, and this amount will be subject to certain additional adjustments after closing. We paid expenses associated with the acquisition of approximately $2.9 million ($1.3 million in 2009 and $1.6 million at closing).

        We used a portion of the net proceeds from a $300 million senior secured notes offering and a $37 million equity offering completed in December 2009 to finance the cash portion of the acquisition, repay existing borrowings and capital lease and other obligations, which totaled approximately $66.7 million as of December 31, 2009. The balance of the proceeds will be used for general corporate purposes.

        Also in connection with the PGS Onshore acquisition, we agreed to expand our board of directors from seven to nine members, and to appoint two persons selected by PGS as directors. One of these

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persons must be independent as defined by the rules of the NYSE Amex. We have agreed to use reasonable best efforts to nominate two persons selected by PGS at each annual meeting of our stockholders, one of which must be independent, for so long as PGS owns at least 10% of our outstanding shares of common stock, and have agreed to nominate one person as a director for so long as Petroleum Geo-Services owns at least 5% of our common stock.

        Avista Capital Partners L.P. ("Avista") and the other holders of the series B-1 preferred stock have agreed to vote the shares of common stock and series B-1 preferred stock they own for the election of the PGS nominees at the 2010 and 2011 annual meetings of our stockholders.

Common Stock Offering

        On December 18, 2009, we completed the offering of 4,000,000 shares of our common stock at $9.25 per share. Total proceeds from this offering were approximately $34.8 million. In addition, on January 14, 2010, the underwriters purchased 207,200 shares pursuant to an overallotment option for approximately $1.8 million.

        As a result of the equity offering on December 18, 2009, the purchase price of the warrants owned by Avista to purchase 240,000 shares of Geokinetics common stock at $20.00 per share issued on July 28, 2008 was adjusted to $9.25 per share pursuant to certain existing provisions of the warrants.

Preferred Stock Restructuring

        In December 2006, we issued series B-1 preferred stock to affiliates of Avista and another institutional investor, and in July 2008, we issued shares of series B-2 preferred stock and warrants to purchase 240,000 shares of our common stock to Avista. In connection with the PGS Onshore acquisition and the common stock offering, on December 18, 2009, we restructured the series B-1 preferred stock to reduce the conversion price from $25 to $17.436, to increase the dividend of the series B-1 preferred stock to 9.75%, to extend the dates on which we may pay interest in kind and after which we are required to redeem the series B-1 preferred stock until one year after the maturity date of the notes, and to waive certain other provisions of the series B-1 preferred stock to facilitate the acquisition. We have agreed to pay Avista Capital Holdings, L.P. and Levant America S.A. a fee of $2.1 million, which is 2% of the liquidation amount of the preferred stock.

        Additionally, we agreed to exchange the series B-2 preferred stock for a new series of preferred stock, Series C, plus the issuance of 750,000 shares of our common stock. The new preferred stock is not convertible, and has a dividend rate of 11.75% and an aggregate liquidation amount of $32.8 million. We will pay dividends on the new preferred stock in kind or allow them to accrue without being paid, and will not be required to redeem the new preferred stock for the liquidation amount, until one year after the maturity of the notes, December 15, 2015. The new series of preferred stock will be considered a mandatorily redeemable financial instrument that is within the scope of ASC 480, "Distinguishing liabilities from equity" and therefore will be classified a long-term liability. The dividends payable on the new series of preferred stock will be classified as interest expense.

Senior Secured Notes Due 2014

        On December 23, 2009, one of our wholly owned subsidiaries, Geokinetics Holdings, USA, Inc., issued $300 million senior secured notes due 2014 (the "Notes") in a private placement to institutional buyers at an issue price of 98.093% of the principal amount or approximately $294.3 million.

        The Notes bear interest at the rate of 9.75% per year, payable semi-annually in arrears on June 15 and December 15 of each year, with interest payments commencing in June 2010. The Notes are fully and unconditionally guaranteed, jointly and severally, by us, and by each of our current and future domestic subsidiaries.

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        Until the second anniversary following their issuance, we may redeem up to 10% of the original principal amount of the Notes during each 12-month period at 103% of the principal amount plus accrued interest. Thereafter, we may redeem all or part of the Notes at a prepayment premium which will decline over time. We will be required to make an offer to repurchase the Notes at 101% of the principal amount plus accrued interest if we experience a change of control. The indenture for the Notes contains customary covenants for non-investment grade indebtedness, including restrictions on our ability to incur indebtedness, to declare or pay dividends and repurchase our capital stock, to invest the proceeds of asset sales, and to engage in transactions with affiliates.

        As required by the Notes indenture, at closing, we deposited into escrow $303.8 million, which was 101% of the aggregate issue price of the Notes, plus an amount necessary to pay the interest on the Notes from and including the issue date of the Notes to, but excluding, March 15, 2010. The holders of the Notes had a first priority lien on the amounts in the escrow account. This amount was in escrow on December 31, 2009 and was released in connection with the closing of the PGS Onshore acquisition on February 12, 2010. We used a portion of the amounts released from escrow to pay the cash portion of the purchase price of the PGS Onshore acquisition, repay existing indebtedness and to pay related expenses.

New Senior Secured Revolving Credit Facility

        On February 12, 2010, one of our wholly owned subsidiaries, Geokinetics Holdings USA, Inc., entered into a new $50.0 million senior secured revolving credit facility with Royal Bank of Canada. The revolving credit facility will mature on February 12, 2013. Borrowings outstanding under the revolving credit facility will bear interest at a floating rate based on the greater of: i) 3% per year, ii) Prime Rate, iii) 0.5% above the Federal Funds Rate, or iv) 1% above one month LIBOR; plus an applicable margin between 4.25% and 5.25% until June 29, 2010. Beginning June 30, 2010, the applicable margin will range between 3.5% and 5.5% depending on our total leverage ratio.

        Borrowings under the revolving credit facility are unconditionally guaranteed by Geokinetics and each of its existing and each subsequently acquired or organized wholly-owned U.S. direct or indirect material subsidiary of Geokinetics. Each of the entities guaranteeing the revolving credit facility will secure the guarantees on a first priority basis with a lien on substantially all of the assets of such guarantor. Borrowings under the revolving credit facility are deemed Priority Bank Debt under an inter-creditor agreement with the holders of the Notes, and so the Notes will be effectively subordinated to borrowings under the revolving credit facility pursuant to such inter-creditor agreement.

        Availability under the revolving credit facility is subject to compliance with certain terms, conditions, representations and warranties, including the maintenance of certain financial and non-financial covenants. The financial covenants include a total leverage ratio, an interest coverage ratio and a fixed charge coverage ratio. In addition, the senior secured revolving credit facility will require mandatory prepayments (but without corresponding commitment reductions) from the proceeds of certain asset sales (subject to customary reinvestment rights), certain debt or equity issuances and receipts of extraordinary amounts. Certain voluntary prepayments and commitment reductions are also permitted.

        No amounts were drawn under the senior secured revolving credit facility on the closing date of the PGS Acquisition, other than the issuance of letters of credit in the amount of approximately $2.3 million.

Other

        Our Board of Directors has approved a capital expenditure budget for 2010 of $65.3 million, which is an increase of 57% from capital expenditures in 2009. We expect investments in 2010 to be primarily

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targeted toward expansion of our shallow water capabilities, expansion of our international operations and maintenance capital expenditures.

        In addition, our Board of Directors has approved multi-client data library investments for 2010 of $47.0 million to date subject to certain minimum pre-funding levels. This amount does not include any amounts for multi-client data library investments related to PGS Onshore which will be approved at a later date. We expect our investments in 2010 to be primarily focused on the expansion of our existing multi-client data library interests in the Marcellus Shale in Pennsylvania.

Industry Overview

        Seismic surveys enable E&P companies to determine whether subsurface conditions are favorable for finding oil and natural gas accumulations and to determine the size and structure of previously identified oil and natural gas deposits. Seismic surveys consist of the acquisition and processing of 2D and 3D seismic data, which is used to produce computer-generated, graphic cross-sections, maps and 3D images of the subsurface. These resulting images are then analyzed and interpreted by geophysicists and used by E&P Companies to assist in acquiring prospective oil and natural gas drilling rights, select drilling locations on exploratory prospects and to manage and develop producing reservoirs.

        Seismic data is acquired by crews operating in land, transition zone and marine environments. Seismic data is generated by the propagation of sound waves near the earth's surface by controlled sources, such as dynamite or vibration equipment. The waves radiate into the earth and are reflected back to the surface and collected by data collection devices known in the industry as "geophones." Multiple geophones are strategically positioned, according to client requirements, and connected as a single recording channel to acquire data. This data is then input into a specialized data processing system that enhances the recorded signal by reducing noise and distortion, improving resolution and arranging the input data to produce an image of the subsurface. 3D seismic surveys collect far more information and generate significantly greater detail of the underlying reservoirs than 2D surveys.

        The overall demand for seismic data and related seismic services is dependent upon spending by E&P companies for exploration, production, development and field management activities, which, in turn, is driven largely by present and expected future prices for oil and natural gas and the need to replenish drilling prospects and reserves. This is impacted by supply and demand, global and local events, as well as political, economic and environmental considerations.

        For OBC operations, an assembly of vertically oriented geophones and hydrophones connected by electrical wires typically is deployed on the seafloor to record and relay data to a seismic recording vessel. Such systems were originally introduced to enable surveying in areas of obstructions (such as production platforms) or shallow water inaccessible to ships towing seismic streamers (floating cables).

        Global energy demand growth.    Although demand for energy has recently declined, we believe that long-term, global demand for energy will increase and as that demand rebounds, demand from E&P companies for seismic services will also increase.

        E&P capital spending.    The need to replace depleting reserves should encourage capital expenditures by E&P companies, which we expect will benefit the seismic services industry. We believe that E&P companies, including many national oil and gas companies, remain under pressure to increase or replenish reserves and are looking to unconventional resource plays, transition zones, international locations and the optimization of current reserves with new technology to achieve these results. Seismic data acquisition services are a key component of E&P companies' capital expenditure programs.

        Technological development.    The application and utilization of seismic services have considerably increased over the last several years as a result of significant technological advancements, such as the

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move from 2D to 3D and single-component to multi-component seismic data recording and processing. Seismic services can now be applied to the entire sequence of exploration, development and production, as opposed to exploration only, allowing for a greater range of use for our services. In addition, surveys previously shot 2D or single-component are often being reshot with newer techniques to give greater clarity to the subsurface.

Business Segments

        We are organized into two reportable segments: seismic data acquisition and seismic data processing and interpretation. We further break down its seismic data acquisition segment into two geographic reporting units: North American seismic data acquisition and international seismic data acquisition. For the fiscal years ending December 31, 2009, 2008 and 2007, our North American seismic data acquisition services represented 16%, 37%, and 47% of total revenues, international seismic data acquisition services represented 82%, 60%, and 50%, and data processing and interpretation services represented 2%, 3%, and 3% of total revenues, respectively. We continue to focus on diversifying and expanding into new international markets and expect international data acquisition revenues to continue to provide the majority of total revenues.

Seismic Data Acquisition Services

        Through our subsidiaries, we engage in seismic data acquisition services in land, transition zone and shallow water environments on a contract basis for our customers. Our equipment is capable of collecting 2D, 3D and multi-component seismic data. We have a pro forma recording capacity of approximately 206,000 channels that can be configured to operate up to 38 crews worldwide. Most of our seismic data acquisition services involve 3D surveys. The crews are scalable and specially configured for each project; the number of individuals on each crew is dependent upon the size and nature of the seismic survey requested by the customer.

        On a typical land seismic survey, the seismic recording crew is supported by a surveying crew and a drilling crew. The surveying crew lays out the line locations to be recorded and identifies the sites for shot-hole placement. The drilling crew creates the holes for the explosive charges that produce the necessary acoustical impulse. A mechanical vibrating unit is used in areas where explosives are not utilized. The seismic crew lays out the geophones and recording instruments, directs shooting operations and records the acoustical signal reflected from subsurface strata. In the United States and Canada, the survey crew and drill crew are typically provided by third parties and supervised by our personnel. Outside the United States and Canada, we perform our own surveying and drilling. A fully staffed seismic land crew typically consists of at least one party manager, observer, head linesman and crew laborers. The number of individuals on each crew is dependent upon the size and nature of the seismic survey requested by the customer but can be extensive in certain parts of the world. A typical international land crew may be up to ten times the size of a typical North American land crew. We use helicopters to assist the crews in seismic data acquisition services in circumstances where such use will reduce overall costs and improve productivity. A typical transition zone or OBC crew utilizes numerous vessels and air guns as the energy source to record seismic data.

        Typically, our contracts provide that the seismic data we acquired is the exclusive property of the customer. To a lesser extent, we collect and process geophysical data for our own account and retain ownership rights. We license the data to customers on a non-transferable basis through a third party. In some circumstances, we sell, on a non-exclusive basis, rights to the data prior to collecting and processing such data, i.e., we make multiple discrete sales of licenses to the same data. For the years ended December 31, 2009, 2008 and 2007, seismic data acquisition services generated revenues of $500.3 million, $462.6 million, and $346.8 million, respectively. Of these segment revenues, for the year ended December 31, 2009, North American operations accounted for 17% and international operations accounted for 83%.

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        Seismic data acquisition services contracts, whether bid or negotiated, provide for payment on either a turnkey or term (also referred to as "day-rate") basis, or on a combination of both methods. A turnkey contract provides for a fixed fee to be paid for data acquired. Such a contract causes us to bear varying degrees of business interruption risk caused by weather delays and other hazards. Our seismic data acquisition services are performed outdoors and are therefore subject to seasonality. Adverse weather negatively impacts our ability to provide services in certain regions. Term contracts provide for payments based on agreed rates per units of time, which may be expressed in periods ranging from days to months. This type of contract causes the customer to bear substantially all of the business interruption risks. When a combination of both turnkey and term methods is used, the risk of business interruption is shared by us and the customer. In either case, progress payments are usually required unless it is expected the job can be accomplished in a short period. Our contracts for seismic data acquisition services are predominantly turnkey contracts.

Seismic Data Processing

        We also provide a full suite of onshore and offshore proprietary seismic data processing and interpretation products and services to complement our data acquisition services. Seismic data is processed to produce an image of the earth's subsurface using proprietary computer software and internally developed techniques. Our seismic data processing and interpretation centers in the United States and the United Kingdom process 2D and 3D seismic data acquired by our own crews as well as data acquired by other seismic data acquisition companies.

        Our expansion into the United Kingdom in 2003 facilitated the penetration of a wider range of geographic markets, provided access to worldwide technology trends and strengthened our overall seismic and management expertise. A majority of our seismic data processing and interpretation services are performed on 3D seismic data. We also re-process older seismic data using new techniques designed to enhance the quality of the data. Substantially all of our data processing services contracts are on a turnkey basis.

        The seismic data processing services industry is highly technical and the technological requirements for the acquisition and processing of seismic data have increased continuously over time. Thus, we must continually take steps to ensure that our technological capabilities are comparable or superior to those of our competitors, whether through continuing research and development, strategic alliances with equipment manufacturers or acquisitions of technology through licenses from others. We have introduced several technological innovations that have become industry-standard products in the seismic data processing business, including our proprietary amplitude variation with offset ("AVO") reflectivity process. Since 2005, we have made significant investments to upgrade our technology in the areas of pre-stack time and depth imaging, multi-component and four-dimensional ("4D") seismic data processing through technology joint ventures and proprietary developments. Our Gulf of Mexico well log database and rock properties database continue to be unique products offered in the seismic data processing and interpretation services area. We actively market our seismic data processing and interpretation services in conjunction with our seismic data acquisition services to enhance total value provided to our customers. We have experienced improved operating results in this segment, which is the result of continuous improvements in technology, job mix, and cost structure throughout the year.

Marketing

        Our seismic data acquisition services and seismic data processing and interpretation services are marketed from various offices around the world. We maintain offices in Canada, Latin America, Europe, the Middle East, Australia, Africa, Asia, the Far East and our corporate headquarters in Houston, Texas, from which we market and/or perform services.

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        While we rely upon the utilization of our personnel to make sales calls, we receive a significant amount of work through word-of-mouth referrals, repeat customer sales, our industry reputation and the experience and skills of our personnel.

        Seismic data acquisition services and seismic data processing and interpretation services contracts are obtained either through competitive bidding in response to invitations to bid, or by direct negotiation with a prospective customer. A significant portion of our contracts result from competitive bidding. Contracts are generally denominated in U.S. dollars and are awarded primarily on the basis of price, experience, availability, technological expertise and reputation for dependability and safety.

Customers

        For the year ended December 31, 2009, our top ten customers were Sonangol, Petroandina, Petrobel, Petroleo Brasileiro S.A.-Petrobras ("Petrobras"), ANH Sinu, Staatsolie, Agência Nacional do Petróleo ("ANP"), Petronas Carigali Pertamina Petrovietnam Operating Company, Sdn bhd.("PCPPOC"), International Egyptian Oil Company ("IEOC"), and Seismic Exchange , Inc. These top 10 customers represented 70% of our consolidated revenue for 2009.

        Our two largest customers in 2009, Sonangol and Petroandina, accounted for 20% and 14% of total revenue, respectively. Because of the nature of our contracts and customers' projects, our largest customers can change from year to year and the largest customers in any year may not be indicative of the largest customers in any subsequent year.

        We have a large, diversified customer base. While the loss of one customer or one particular contract may have a short-term negative impact, we do not believe that any of our customers or contracts, including that with Sonangol or Petroandina, is material, especially in light of the customer's ability to cancel the contracts as disclosed in Item 1A, Risk Factors.

Backlog

        Even though the oil and gas business has experienced a period of reduced spending on exploration and development in certain markets due to the recent economic recession and other factors, our backlog is in line with pre-2008 levels. At December 31, 2009, we estimated our total backlog of commitments for services was approximately $190.2 million compared to estimated total backlog of commitments for services of approximately $548.3 million at December 31, 2008. Backlog at December 31, 2009 included $160.2 million from international operations, $30.0 million from North American operations, including $20.8 million in the United States, $5.0 million in Canada, and $4.1million from the data processing segment. It is anticipated that the majority of the backlog at December 31, 2009, will be completed in 2010 with the remaining amount to be completed in 2011. On a pro-forma basis with PGS Onshore, which we acquired on February 12, 2010, total backlog was $378.2 million as of December 31, 2009 of which $89.0 million are North American projects and $289.2 million are international projects. This backlog consists of written orders or commitments believed to be firm. Contracts for services are occasionally varied or modified by mutual consent and in many instances may be cancelled by the customer on short notice without penalty. As a result, our backlog as of any particular date may not be indicative of our actual operating results for any succeeding fiscal period.

Competition

        The acquisition and processing of seismic data for the oil and natural gas industry are highly competitive businesses. Competition is based on the type and capability of equipment used to conduct seismic surveys and the availability of such equipment. In addition to these factors, price, experience, availability, technological expertise and reputation for dependability and safety of a crew significantly affect a potential customer's decision to award a contract to us or one of our competitors. We believe

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some of our competitors have more extensive and diversified operations and also have financial, operating and other resources substantially in excess of those available to us.

        Our principal competitors in the seismic data acquisition services segment include Bureau of Geophysical Prospecting, WesternGeco, Compagnie Générale de Géophysique-Veritas ("CGV"), Dawson Geophysical Company, Petroleum Geo-Services ASA ("PGS"), Tidelands Geophysical Company and Global Geophysical, Inc.

        In addition, in the international markets in which we operate, we compete with various smaller local competitors. Our principal competitors in the seismic data processing services segment include CGV, PGS, Geotrace Technologies, Inc., GX Technology Corporation, WesternGeco and a number of smaller companies.

Regulation

        Our operations are subject to numerous international, federal, state and local laws and regulations. These laws and regulations govern various aspects of operations, including the discharge of explosive materials into the environment, requiring the removal and clean-up of materials that may harm the environment or otherwise relating to the protection of the environment and access to private and governmental land to conduct seismic surveys. We believe we have conducted our operations in substantial compliance with applicable laws and regulations governing our activities.

        Our Quality, Health, Safety and Environmental ("QHSE") department is generally responsible for our meeting and remaining in compliance with certain regulatory requirements. We have QHSE Advisors who maintain and administer the Quality, Health, Safety and Environmental programs for our field personnel. The costs of acquiring permits and remaining in compliance with environmental laws and regulations, title research, environmental studies, archeological surveys and cultured resource surveys are generally borne by our customers.

        Although the costs of complying with applicable laws and regulations have historically not been material, the changing nature of such laws and regulations makes it impossible to predict the cost or impact of such laws and regulations on our future operations.

Research and Development

        We rely on certain proprietary information, proprietary software, trade secrets and confidentiality and licensing agreements to conduct our current operations. Our future success will depend, in part, on our ability to maintain and preserve our intellectual property, without infringing on the rights of any third parties. There can be no assurance that we will be successful in protecting our intellectual property or that our competitors will not develop technologies that are substantially equivalent or superior to our technologies. We are continuously working to improve our technology and operating techniques, primarily through on-the-job learning and advancement as well as working with our vendors to develop new technologies for us. While we did not have a formal company-wide research and development program in place during the periods presented, we have performed informal research and development activities.

Employees

        At December 31, 2009, we had approximately 4,400 employees, all of which were full-time employees. None of our employees are a party to a collective bargaining agreement. We consider relations with our employees to be good.

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Other

        Through a combination of our internal controls and our policy related to conflicts of interest contained in our code of business conduct and ethics, we were made aware in December 2008 of a previously unreported related party transaction. In 2002, officers and other employees of Grant's Colombian operations, together with a third party, formed Serandina, S.A., a catering company which has provided food, drink and other catering services to Grant's Colombian seismic crews in the field since its inception. For the year ended December 31, 2009, 2008 and 2006, we spent approximately $3.3 million, $6.3 million and $3.0 million, respectively with this company. We believe that all transactions have been arm's-length on terms at least as favorable as market rates. We are no longer using services from this company.

Available Information

        All of our reports and materials filed with the SEC, are available free of charge through our website, http://www.geokinetics.com, as soon as reasonably practical, after we have electronically filed such material with the SEC. Information about our Board Members, Board's Standing Committee Charters, and Code of Business Conduct and Ethics are also available, free of charge, through our website. Information contained on our website is not part of this annual report.

        The SEC maintains an Internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC, available at http://www.sec.gov.

Item 1A.    Risk Factors

        The following risk factors, which are not all-inclusive, should be carefully considered, together with all of the other information included in this Form 10-K, including our financial statements and related notes, in evaluating us. Other factors not specifically discussed in this report may also have a material adverse effect on our results. If any of the following risks were actually to occur, our business, financial condition or results of operations could be materially adversely affected.

We are subject to certain risks related to acquisitions, including the PGS Onshore acquisition, and these risks may materially adversely affect our revenues, expenses, operating results and financial condition.

        The PGS Onshore acquisition involves the integration of Geokinetics and PGS Onshore, two businesses that have previously operated independently and as competitors. We acquired PGS Onshore with the expectation that, among other things, the PGS Onshore acquisition will enable us to achieve expected cost synergies. Achieving the benefits of the PGS Onshore acquisition will depend in part upon meeting the challenges inherent in the successful combination and integration of global business enterprises of the size and scope of Geokinetics and PGS Onshore and the possible resulting diversion of management attention for an extended period of time. There can be no assurance that we will meet these challenges and that such diversion will not negatively affect our operations. In addition, delays encountered in the transition process could have a material adverse effect on our revenues, expenses, operating results and financial condition. There can be no assurance that we will actually achieve the anticipated synergies or other benefits from the PGS Onshore acquisition.

        We plan to continue growing through acquisitions of companies and assets. We must plan and manage our acquisitions effectively to achieve revenue growth and maintain profitability in our evolving market. If we fail to manage current and future acquisitions effectively, our results of operations could be adversely affected. Our growth has placed, and is expected to continue to place, significant demands on our personnel, management and other resources. A lack of continued improvement to our operational, financial, management and legal/compliance information systems to keep pace with the growth of our business could have a material adverse effect on us.

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        Any future acquisitions could present a number of risks, including but not limited to:

•

incorrect assumptions regarding the future results of acquired operations or assets or expected cost reductions or other synergies expected to be realized as a result of acquiring operations or assets;



•

failure to integrate the operations or management of any acquired operations or assets successfully and timely and retain key personnel;



•

diversion of management's attention from existing operations or other priorities; and



•

our inability to secure, on terms we find acceptable, sufficient financing that may be required for any such acquisition or investment.

        Our failure to successfully integrate our acquisitions in a timely and cost effective manner could have an adverse affect on our business, financial condition or results of operations.

PGS Onshore may have liabilities which are not known to us.

        As a result of the PGS Onshore acquisition, we have assumed certain liabilities. There may be liabilities that we failed to, or we were unable to discover in the course of performing due diligence investigations on PGS Onshore. We cannot assure you that rights to indemnification by Petroleum Geo-Services to us will be sufficient in amount, scope or duration to fully offset the possible liabilities associated with the business or assets acquired. Any such liabilities, individually or in the aggregate, could have a material adverse effect on our business, financial condition and results of operations. As we integrate PGS Onshore, we may learn additional information about PGS Onshore that adversely affects us, such as unknown or contingent liabilities and issues relating to compliance with applicable laws.

Our business largely depends on the exploration and development activity in the oil and natural gas industry.

        Our business is substantially dependent upon the condition of the oil and natural gas industry and, in particular, the willingness of E&P companies to make capital expenditures for exploration, development and production operations. The level of capital expenditures generally depends on the prevailing views of future oil and natural gas prices, which are influenced by numerous factors, including but not limited to:

•

changes in United States and international economic conditions, including the length and severity of the recent recession and the effect of such recession on economic activity;



•

demand for oil and natural gas;



•

worldwide political conditions, particularly in significant oil-producing regions such as the Middle East, West Africa and Latin America;



•

actions taken by the Organization of Petroleum Exporting Countries, or OPEC;



•

the availability and discovery rate of new oil and natural gas reserves;



•

the rate of decline of existing and new oil and gas reserves;



•

the cost of exploration for, and production and transportation of, oil and natural gas;



•

the ability of E&P companies to generate funds or otherwise obtain external capital for exploration, development, construction and production operations;



•

the sale and expiration dates of leases in the United States and overseas;



•

technological advances affecting energy exploration, production, transportation and consumption;

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•

weather conditions;



•

environmental or other government regulations both domestic and foreign;



•

domestic and foreign tax policies; and



•

the pace adopted by foreign governments for the exploration, development and production of their oil and gas reserves.

        Oil and natural gas prices had been at historically high levels until experiencing a sharp decline during the second half of 2008 and continuing through 2009, particularly for natural gas prices. The natural gas market is a key market for the Company's North American seismic data acquisition business and the multi-client data library it has acquired from PGS Onshore. A worldwide decrease in hydrocarbon demand and a decline in commodity prices have caused many E&P companies to curtail planned capital spending. Historically, demand for our services has been sensitive to the level of exploration spending by oil and gas companies. A sustained period of low drilling and production activity, low commodity prices or reductions in industry budgets could reduce demand for our services and would likely have a material adverse effect on our business, financial condition or results of operations.

Economic conditions could negatively affect our business.

        Our operations are affected by local, national and worldwide economic conditions and the condition of the oil and gas industry. Recent disruptions in the credit markets and concerns about global recession have had a significant adverse impact on global financial markets.

        Future market deterioration could also jeopardize the performance of counterparty obligations, including those of our insurers, suppliers, customers and financial institutions. Although we monitor the creditworthiness of our counterparties, the future disruptions could lead to sudden changes in a counterparty's liquidity. If one of our counterparties fails to perform, our financial results could be adversely affected and we could incur losses and our liquidity could be negatively impacted.

We operate under hazardous conditions that subject us and our employees to risk of damage to property or personal injury and limitations on its insurance coverage may expose us to potentially significant liability costs.

        Our activities are often conducted in dangerous environments and include hazardous conditions, including the detonation of dynamite. Operating in such environments and under such conditions carries with it inherent risks, such as loss of human life or equipment, as well as the risk of downtime or reduced productivity resulting from equipment failures caused by an adverse operating environment. For example, in 2009 two employees of our subcontractors and one our employees suffered fatal injuries. Although we maintain what we believe is prudent insurance protection, we can make no assurances that our insurance will be sufficient or adequate to cover all losses or liabilities or that insurance will continue to be available to us or available to us on acceptable terms. A successful claim for which we are not fully insured, or which exceeds the policy limits of our applicable insurance could have a material adverse effect on our financial condition. Moreover, we do not carry business interruption insurance with respect to our operations.

Historically, we have been dependent on a few customers operating in a single industry; the loss of one or more customers could adversely affect our financial condition and results of operations.

        Our customers are engaged in the oil and natural gas drilling business throughout the world. Historically, we have been dependent upon a few customers for a significant portion of our revenue. For the years ended December 31, 2009, 2008 and 2007, our top ten customers collectively represented approximately 70%, 47% and 55% of total revenues, respectively. Our three largest customers in 2009,

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2008 and 2007 accounted for 45%, 19% and 27% of total revenues, respectively. This concentration of customers may increase our overall exposure to credit risk, and customers will likely be similarly affected by changes in economic and industry conditions. If any of these significant clients were to terminate their contracts or fail to contract for our services in the future because they are acquired, alter their exploration or development strategy, or for any other reason, our results of operations could be affected.

We have invested, and expect to continue to invest, significant amounts of money in acquiring and processing seismic data for multi-client surveys and for our seismic data library without knowing precisely how much of this seismic data we will be able to sell or when and at what price we will be able to sell such data.

        Multi-client surveys and the resulting seismic data library are an increasingly important part of our business and our future investments. We invest significant amounts of money in acquiring and processing seismic data that we either exclusively or partially own. By making such investments, we are exposed to the following risks:

•

We may not fully recover our costs of acquiring, processing and interpreting seismic data through future sales. The amounts of these data sales are uncertain and depend on a variety of factors, many of which are beyond our control.



•

The timing of these sales is unpredictable and can vary greatly from period to period. The costs of each survey are capitalized and then amortized as a percentage of sales and/or over the expected useful life of the data. This amortization will affect our earnings and when combined with the sporadic nature of sales, will result in increased earnings volatility.



•

Regulatory changes that affect companies' ability to drill, either generally or in a specific location where we have acquired seismic data, could materially adversely affect the value of the seismic data contained in our library. Technology changes could also make existing data sets obsolete. Additionally, each of our individual surveys has a limited book life based on its location and oil and gas companies' interest in prospecting for reserves in such location, so a particular survey may be subject to a significant decline in value beyond our initial estimates.



•

The value of our multi-client data could be significantly adversely affected if any material adverse change occurs in the general prospects for oil and gas exploration, development and production activities.



•

The cost estimates upon which we base our pre-commitments of funding could be wrong. The result could be losses that have a material adverse effect on our financial condition and results of operations. These pre-commitments of funding are subject to the creditworthiness of our clients. In the event that a client refuses or is unable to pay its commitment, we could lose a material amount of money.

        Any reduction in the market value of such data will require us to write down its recorded value, which could have a significant material adverse effect on our results of operations.

The seismic data acquisition services industry is capital intensive and sources of cash to finance our capital expenditures may not always be available. If financing is not available, our results of operations will be negatively affected.

        Seismic data acquisition equipment is continually being improved with new technology. In order to remain competitive, we must continue to invest additional capital to maintain, upgrade and expand its seismic data acquisition capabilities. Seismic data acquisition equipment is expensive and our ability to operate and expand our business operations is dependent upon the availability of internally generated cash flow and financing alternatives. Such financing may consist of bank or commercial debt, equity or debt securities or any combination thereof. There can be no assurance that we will be successful in

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obtaining sufficient capital to upgrade and expand our current operations through cash from operations or additional financing or other transactions if and when required on terms acceptable to us. Due to the uncertainties surrounding the changing market for seismic services, increases in capital and technological requirements, and other matters associated with our operations, we are unable to estimate the amount or terms of any financing that it may need to acquire, upgrade and maintain seismic equipment. If we are unable to obtain such financing, if and when needed, we may be forced to curtail our business objectives, and to finance our business activities with only such internally generated funds as may then be available.

Our high level of fixed costs can leave us vulnerable to downturns in revenues, which can result in losses.

        We are subject to high fixed costs which primarily consist of depreciation, maintenance expenses associated with our seismic data acquisition, processing and interpretation equipment and certain crew costs. Extended periods of significant downtime or low productivity caused by reduced demand, weather interruptions, equipment failures, permit delays or other causes could reduce our profitability and have a material adverse effect on our financial condition and results of operations because we will not be able to reduce our fixed costs as fast as revenues decline.

We face intense competition in our business that could result in downward pricing pressure and the loss of market share.

        Competition among seismic contractors historically has been, and likely will continue to be, intense. Competitive factors have in recent years included price, crew experience, equipment availability, technological expertise and reputation for quality and dependability. We also face increasing competition from nationally-owned companies in various international jurisdictions that operate under less significant financial constraints than those we experience. Many of our competitors have greater financial and other resources, more clients, greater market recognition and more established relationships and alliances in the industry than we do. Additionally, the seismic data acquisition services business is extremely price competitive and has a history of protracted periods of months or years where seismic contractors under financial duress bid jobs below cost and therefore adversely impact industry pricing. Competition from these and other competitors could result in downward pricing pressure and the loss of market share.

We rely on a limited number of key suppliers for specific seismic services and equipment.

        We depend on a limited number of third parties to supply us with specific seismic services and equipment. From time to time, increased demand for seismic data acquisition services has decreased the available supply of new seismic equipment, resulting in extended delivery dates on orders. Any delay in obtaining equipment could delay our implementation of additional crews and restrict the productivity of its existing crews, adversely affecting our business and results of operations. In addition, any adverse change in the terms of our supplier arrangements could affect our results of operations.

Revenue derived from our projects may not be sufficient to cover our costs of completing those projects. As a result, our results of operations may be adversely affected.

        Our revenue is determined, in part, by the price we receive for our services, the productivity of our crew and the accuracy of our cost estimates. Our crew's productivity is partly a function of external factors, such as weather and third party delays, over which we have no control. In addition, cost estimates for our projects may be inadequate due to unknown factors associated with the work to be performed and market conditions, resulting in cost over-runs. If our crew encounters operational difficulties or delays, or if we have not correctly priced our services, our results of operation may vary, and in some cases, may be adversely affected.

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        Many of our projects are performed on a turnkey basis where a defined amount and scope of work is provided by us for a fixed price and extra work, which is subject to client approval, is billed separately. The revenue, cost and gross profit realized on a turnkey contract can vary from our estimated amount because of changes in job conditions, variations in labor and equipment productivity from the original estimates, and the performance of subcontractors. Turnkey contracts may also cause us to bear substantially all of the risks of business interruption caused by weather delays and other hazards. These variations, delays and risks inherent in billing clients at a fixed price may result in us experiencing reduced profitability or losses on projects.

Our clients could delay, reduce or cancel their commitments or service contracts with us on short notice, which may lead to lower than expected demand and revenues.

        Our backlog consists of written orders or commitments for our services that we believe to be firm. At December 31, 2009, our backlog for our seismic data acquisition and seismic data processing and interpretation segments was approximately $190.2 million. Backlog levels vary during the year depending on the timing of the completion of certain projects and when new projects are awarded and contracts are signed. Because of potential changes in the scope or schedule of our clients' projects, we cannot predict with certainty when or if our backlog will be realized. Even where a project proceeds as scheduled, it is possible that the client may default and fail to pay amounts owed to us. In addition, the contracts in our backlog are cancelable by the client. Material delays, payment defaults or cancellations would reduce the amount of backlog currently reported, and, consequently, could inhibit the conversion of that backlog into revenue which may materially affect our financial condition, results of operations and cash flows.

Our agreements with our clients may not adequately protect us from unforeseen events or address all issues that could arise with our clients. The occurrence of unforeseen events, or disputes with clients not adequately addressed in the contracts could result in increased liability, costs and expenses associated with any given project.

        We enter into master service agreements with many of our clients which allocate certain operational risks. For example, we seek to minimize the risk of delays through the inclusion of "standby rate" provisions which provide for payment to us of a reduced rate for a limited amount of time if the weather conditions or certain other factors outside of our control prevent us from recording data. Despite the inclusion of risk allocation provisions in our agreements, our operations may be affected by a number of events that are unforeseen or not within our control. We cannot assure you that our agreements will adequately protect us from each possible event. If an event occurs which we have not contemplated or otherwise addressed in our agreement, we, and not our client, will likely bear the increased cost or liability. To the extent our agreements do not adequately address these and other issues, or we are not able to successfully resolve resulting disputes, we may incur increased liability, costs and expenses.

We may be held liable for the actions of our subcontractors.

        We often work as the general contractor on seismic data acquisition surveys and consequently engage a number of subcontractors to perform services and provide products. While we obtain contractual indemnification and insurance covering the acts of these subcontractors, and require the subcontractors to obtain insurance for our benefit, there can be no assurance we will not be held liable for the actions of these subcontractors. In addition, subcontractors may cause damage or injury to our personnel and property that is not fully covered by insurance.

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Our results of operations can be significantly affected by currency fluctuations.

        Because we conduct a substantial amount of our operations internationally, we are subject to risks relating to fluctuations in currency exchange rates. Fluctuations in the exchange rate of the U.S. dollar against such other currencies may, in future periods, have a significant effect upon our results of operations. While we attempt to reduce the risks associated with such exchange rate fluctuations, we cannot assure you that we will be effective in doing so or that fluctuations in the value of the currencies in which we operate will not materially affect our results of operations in the future.

Our operations outside of the United States are subject to additional political, economic, and other uncertainties that could adversely affect our business, financial condition or results of operations, and our exposure to such risks will increase as we expand our international operations.

        Over the past several years, our operations have become increasingly international. For the years ended December 31, 2009, 2008 and 2007, 83%, 62%, and 52%, respectively, of our actual revenues from our seismic data acquisition services segment were derived outside of the U.S. and Canada. The PGS Onshore acquisition is expected to further increase our international operations. Our operations outside of the United States are subject to risks inherent in foreign operations, including but not limited to:

•

government instability, which can cause investment in capital projects by our potential clients to be withdrawn or delayed, reducing or eliminating the viability of some markets for our services;



•

potential expropriation, seizure, nationalization or detention of assets;



•

difficulty in repatriating foreign currency received in excess of local currency requirements;



•

civil uprisings, riots and war, which can make it unsafe to continue operations, adversely affect both budgets and schedules and expose us to losses;



•

availability of suitable personnel and equipment, which can be affected by government policy, or changes in policy, which limit the importation of qualified crewmembers or specialized equipment in areas where local resources are insufficient;



•

decrees, laws, regulations, interpretation and court decisions under legal systems, which are not always fully developed and which may be retroactively applied and cause us to incur unanticipated and/or unrecoverable costs as well as delays which may result in real or opportunity costs; and



•

terrorist attacks, including kidnappings and assassinations of our personnel.

        In addition, laws and policies of the United States affecting foreign trade and taxation may also adversely affect our international operations.

As a company subject to compliance with the Foreign Corrupt Practices Act (the "FCPA"), our business may suffer because our efforts to comply with U.S. laws could restrict our ability to do business in foreign markets relative to our competitors who are not subject to U.S. law. Any determination that we or our foreign agents or joint venture partners have violated the FCPA, may adversely affect our business and operations.

        We and our local partners operate in many parts of the world that have experienced governmental corruption to some degree and, in certain circumstances, strict compliance with anti-bribery laws may conflict with local customs and practices. We may be subject to competitive disadvantages to the extent that our competitors are able to secure business, licenses or other preferential treatment by making payments to government officials and others in positions of influence or using other methods that U.S. law and regulations prohibit us from using. As a U.S. corporation, the Company is subject to the regulations imposed by the FCPA, which generally prohibits U.S. companies and their intermediaries

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from making improper payments to foreign officials for the purpose of obtaining or keeping business. In particular, we may be held liable for actions taken by our strategic or local partners even though our partners are not subject to the FCPA. Any such violations could result in substantial civil and/or criminal penalties and might adversely affect our business, results of operations or financial condition. In addition, our ability to continue to work in such foreign markets could be adversely affected if we were found to have violated certain U.S. laws, including the FCPA.

We are subject to compliance with stringent environmental laws and regulations that may expose us to significant costs and liabilities.

        Our operations are subject to stringent federal, provincial, state and local environmental laws and regulations in the United States and foreign jurisdictions relating to environmental protection. These laws and regulations may impose numerous obligations that are applicable to our operations including:

•

the acquisition of permits before commencing regulated activities; and



•

the limitation or prohibition of seismic activities in environmentally sensitive or protected areas such as wetlands or wilderness areas.

        Numerous governmental authorities, such as the Federal Environmental Protection Agency and analogous state agencies in the United States and governmental bodies with control over environmental matters in foreign jurisdictions, have the power to enforce compliance with these laws and regulations and any permits issued under them, oftentimes requiring difficult and costly actions. Failure to comply with these laws, regulations and permits may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of injunctions limiting or preventing some or all of our operations.

        There is inherent risk of incurring significant environmental costs and liabilities in our operations due to our controlled storage, use and disposal of explosives. Although we believe that our safety procedures for handling and disposing of explosives comply with the standards prescribed by applicable laws and regulations, the risk of accidental injury from these materials cannot be completely eliminated. In the event of an accident, we could be held liable for any damages that result or we could be penalized with fines, and any liability could exceed the limits of or fall outside our insurance coverage.

Current or future distressed financial conditions of customers could have an adverse impact on us in the event these customers are unable to pay us for the services we provide.

        Some of our customers are experiencing, or may experience in the future, severe financial problems that have had or may have a significant impact on their creditworthiness. Although we perform ongoing credit evaluations of our customers' financial conditions, we generally require no collateral from our customers. We cannot provide assurance that one or more of its financially distressed customers will not default on their obligations to us or that such a default or defaults will not have a material adverse effect on our business, financial position, future results of operations, or future cash flows. Furthermore, the bankruptcy of one or more of our customers, or some other similar proceeding or liquidity constraint, might make it unlikely that we would be able to collect all or a significant portion of amounts owed by the distressed entity or entities. In addition, such events might force such customers to reduce or curtail their future use of our products and services, which could have a material adverse effect on our results of operations and financial condition.

Our seismic data acquisition services revenues are subject to seasonal conditions and customers' budgeting cycles.

        Our seismic data acquisition services are performed outdoors and are therefore subject to seasonality. Shorter winter days and adverse weather negatively impact our ability to provide services in

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certain regions. Additionally, we have limited control over the timing of our international operations due to the extensive planning and preparation required to perform a seismic survey. Our international operations have also been affected historically by the budgeting cycle of our customers, at times resulting in higher activity levels early in the year when available exploration budgets are high, and late in the year when our customers are trying to utilize their remaining budgets.

We may be unable to retain and attract management and skilled and technically knowledgeable employees.

        Our continued success depends upon retaining and attracting highly skilled employees. A number of our employees possess many years of industry experience and are highly skilled and our inability to retain such individuals could adversely affect our ability to compete in the seismic service industry. We may face significant competition for such skilled personnel, particularly during periods of increased demand for seismic services. Although we utilize employment agreements, stock-based compensation and other incentives to retain certain of our key employees, there is no guarantee that we will be able to retain these personnel.

Our operating results from seismic data acquisition services can be significantly impacted from quarter to quarter due to a change in the timing of a few large jobs occurring at any one time.

        We have the capacity to field up to 38 seismic data acquisition crews after the PGS acquisition. However, in any given period, we could have idle crews which result in a significant portion of its revenues, cash flows and earnings coming from a relatively small number of crews. Additionally, due to location, service line or particular job, some of our individual crews may achieve results that are a significant percentage of consolidated operating results. Should one or more of these crews experience significant changes in timing, our financial results are subject to significant variations from period to period. Factors that may result in these changes in timing include, but are not limited to, weather, permits, customer requirements and political unrest.

Our results of operations could be adversely affected by asset impairments.

        We periodically review our portfolio of equipment and intangible assets, including our multi-client data library, for impairment. If we expect significant sustained decreases in oil and natural gas prices in the future, we may be required to write down the value of our assets if the future cash flows anticipated to be generated from the related assets falls below net book value. The recent decline in oil and natural gas prices, if sustained, could result in future impairments. If we are forced to write down the value of our goodwill, other intangible assets or equipment, these non-cash asset impairments could negatively affect our results of operations in the period in which they are recorded. See discussion of "Impairment of Long-Lived Assets" included in "Critical Accounting Policies."

The cyclical nature of, or a prolonged downturn in, our industry, could affect the carrying value of our goodwill or other long-lived assets and negatively impact our earnings.

        As of December 31, 2009, we had $73.4 million of goodwill, or 9.4% of total assets. We have recorded goodwill because we paid more for some of our businesses than the fair market value of the tangible and measurable intangible net assets of those businesses at the time of acquisition. We are required to annually assess whether the carrying value of our goodwill has been impaired. This assessment includes many management assumptions including, but not limited to, business forecasts, risk premiums, cost of capital and market factors. Should any one or combination of these factors change, it could negatively impact our future assessments of the carrying values of these assets. If management determines that the carrying value of our long-lived assets may not be recoverable, our goodwill will be reduced which will adversely affect our earnings.

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Our substantial debt could adversely affect our financial health and prevent us from fulfilling our obligations.

        We have a significant amount of debt and may incur substantial additional debt in the future. As of December 31, 2009, we had total indebtedness of $397.0 million, net of discount. We cannot assure you that we will be able to generate sufficient cash to service our debt or sufficient earnings to cover fixed charges in future years. If new debt is added to our current debt levels, the related risks for us could intensify.

        Our substantial debt could have important consequences. In particular, it could:

•

increase our vulnerability to general adverse economic and industry conditions;



•

require us to dedicate a substantial portion of our cash flow from operations to payments on our indebtedness, thereby reducing the availability of our cash flow to fund capital expenditures and other general corporate purposes;



•

limit our flexibility in planning for, or reacting to, changes in our businesses and the industries in which we operate;



•

place us at a competitive disadvantage compared to our competitors that have less debt; and



•

limit, along with the financial and other restrictive covenants of our indebtedness, among other things, our ability to borrow additional funds.

Our debt agreements contain restrictive covenants that may limit our ability to respond to changes in market conditions or pursue business opportunities.

        Our debt agreements contain restrictive covenants that limit our ability to, among other things:

•

incur or guarantee additional debt;



•

pay dividends;



•

repay subordinated debt prior to its maturity;



•

grant additional liens on our assets;



•

enter into transactions with our affiliates;



•

repurchase stock;



•

make certain investments or acquisitions of substantially all or a portion of another entity's business assets; and



•

merge with another entity or dispose of our assets.

        In addition, our debt agreements require us to maintain certain financial ratios and tests. The requirement that we comply with these provisions may materially adversely affect our ability to react to changes in market conditions, take advantage of business opportunities we believe to be desirable, obtain future financing, fund needed capital expenditures or withstand a continuing or future downturn in our business.

If we are unable to comply with the restrictions and covenants in our debt agreements, there could be a default under the terms of such agreements, which could result in an acceleration of repayment.

        If we are unable to comply with the restrictions and covenants in our debt agreements, there could be a default under the terms of these agreements. Our ability to comply with these restrictions and covenants, including meeting financial ratios and tests, may be affected by events beyond the Company's control. As a result, we cannot assure you that we will be able to comply with these restrictions and covenants or meet such financial ratios and tests. In the event of a default under these

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agreements, lenders could terminate their commitments to lend or accelerate the loans and declare all amounts borrowed due and payable. Borrowings under other debt instruments that contain cross-acceleration or cross-default provisions may also be accelerated and become due and payable. If any of these events occur, our assets might not be sufficient to repay in full all of our outstanding indebtedness and we may be unable to find alternative financing. Even if we could obtain alternative financing, it might not be on terms that are favorable or acceptable to us. Additionally, we may not be able to amend its debt agreements or obtain needed waivers on satisfactory terms.

To service our indebtedness, we require a significant amount of cash, and our ability to generate cash will depend on many factors beyond our control.

        Our ability to make payments on and to refinance our indebtedness, and to fund planned capital expenditures depends in part on our ability to generate cash in the future. This ability is, to a certain extent, subject to general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control. We cannot assure you that we will generate sufficient cash flow from operations to service our indebtedness, or that future borrowings will be available to us in an amount sufficient to enable us to service and repay our indebtedness or to fund our other liquidity needs. If we are unable to satisfy our debt obligations, we may have to undertake alternative financing plans, such as refinancing or restructuring our indebtedness, selling assets, reducing or delaying capital investments or seeking to raise additional capital. We cannot assure you that any refinancing or debt restructuring would be possible, that any assets could be sold or that, if sold, the timing of the sales and the amount of proceeds realized from those sales would be favorable to us or that additional financing could be obtained on acceptable terms. Disruptions in the capital and credit markets, as have been experienced during 2008 and 2009, could adversely affect our ability to meet our liquidity needs or to refinance our indebtedness, including our ability to draw on our existing credit facilities or enter into new credit facilities. Banks that are party to our existing credit facilities may not be able to meet their funding commitments to us if they experience shortages of capital and liquidity or if they experience excessive volumes of borrowing requests from us and other borrowers within a short period of time.

There are inherent limitations in all control systems and failure of our controls and procedures to detect error or fraud could seriously harm our business and results of operations.

        Our management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our internal controls and disclosure controls will prevent all possible error and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. In addition, the design of a control system must reflect the fact that there are resource constraints and the benefit of controls must be relative to their costs. Because of the inherent limitations in all control systems, no evaluation of our controls can provide absolute assurance that all control issues and instances of fraud, if any, will be detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Further, controls can be circumvented by the individual acts of some persons or by collusion of two or more persons. The design of any system of controls is based in part upon the likelihood of future events, and there can be no assurance that any design will succeed in achieving our intended goals under all potential future conditions. Over time, a control may become inadequate because of changes in conditions or the degree of compliance with our policies or procedures may deteriorate. Because of inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur without detection.

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We have identified material weaknesses in our internal controls, which could affect our ability to ensure timely and reliable financial reports and the ability of our auditors to attest to the effectiveness of our internal controls.

        During management's review of our internal controls as of December 31, 2009, control deficiencies that constituted material weaknesses related to the following items were identified:

        Financial Statement Close Process:    During 2009, the Company dedicated significant resources implementing a new management information system and new business processes and controls around domestic and international operations. Due to the demands created by this implementation, the increasing complexity of the Company's international operations and the acquisition and related financing transactions at the end of the year, a material weakness was identified in the Company's financial statement close process, including insufficient controls over analyzing and reconciling accounts, maintaining appropriate support and analyses of certain non-routine accruals, and properly assessing the accounting and reporting implications related to new contractual agreements and certain other accounting matters.

        Taxes Related to International Operations:    Another material weakness was identified by management related to accounting for income taxes associated with the Company's international operations, including insufficient controls and training over the proper identification and application of the relevant tax rules, which affected the Company's calculation of the tax provision of the Company's international operations.

        The Company's lack of resources, in terms of size, technical expertise and institutional knowledge to address certain financial and tax aspects of its multi-national operations, was identified as the underlying cause of these material weaknesses.

        These material weaknesses resulted in the Company recording a number of post-closing adjustments to the Company's 2009 consolidated financial statements. The adjustments primarily affected non-routine accruals, deferred cost accounts, deferred taxes and the tax provision related to the Company's international operations, including, as applicable, the corresponding income statement accounts.

        Based on management's evaluation, because of the material weaknesses described above, management has concluded that our internal control over financial reporting was not effective as of December 31, 2009. Our independent registered public accounting firm, UHY LLP, has audited management's assessment of the effectiveness of our internal control over financial reporting as of December 31, 2009, and their report appears in this Annual Report on Form 10-K.

        While we have taken certain actions to address the deficiencies identified, additional measures will be necessary and these measures, along with other measures we expect to take to improve our internal controls over financial reporting, may not be sufficient to address the deficiencies identified or ensure that our internal control over financial reporting is effective. If we are unable to provide reliable and timely financial external reports, our business and prospects could suffer material adverse effects. In addition, we may in the future identify further material weaknesses or significant deficiencies in our internal control over financial reporting.

Climate Change Legislation or Regulations could result in increased operating costs and reduced demand for the oil and gas our clients intend to produce.

        More stringent laws relating to climate change and greenhouse gases ("GHGs") may be adopted in the future and could reduce the demand for our services. On June 26, 2009, the U.S. House of Representatives passed the "American Clean Energy and Security Act of 2009," or "ACESA," which would establish an economy-wide cap-and-trade program to reduce U.S. emissions of greenhouse gases, including carbon dioxide and methane. ACESA would require a 17% reduction in greenhouse gas

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emissions from 2005 levels by 2020 and just over an 80% reduction of such emissions by 2050. Under this legislation, the EPA would issue a capped and steadily declining number of tradable emissions allowances authorizing emissions of greenhouse gases into the atmosphere. These reductions would be expected to cause the cost of allowances to escalate significantly over time. The net effect of ACESA will be to impose increasing costs on the combustion of carbon-based fuels such as oil, refined petroleum products, and natural gas. The U.S. Senate has begun work on its own legislation for restricting domestic greenhouse gas emissions and the Obama Administration has indicated its support for legislation to reduce greenhouse emissions through an emission allowance system.

        On December 15, 2009, the U.S. Environmental Protection Agency ("EPA") officially published its findings that emissions of carbon dioxide, methane and other "greenhouse gases" present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth's atmosphere and other climatic changes. These findings allow the EPA to adopt and implement regulations that would restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. Accordingly, the EPA has proposed two sets of regulations that would require a reduction in emissions of greenhouse gases from motor vehicles and could trigger permit review for greenhouse gas emissions from certain stationary sources. In addition, on October 30, 2009, the EPA published a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States beginning in 2011 for emissions occurring in 2010.

        Because of the lack of any comprehensive legislative program addressing GHGs, there is a great deal of uncertainty as to how and when federal regulation of GHGs might take place. In addition to possible federal regulation, a number of states, individually and regionally, also are considering or have implemented GHG regulatory programs. These potential regional and state initiatives may result in so-called cap-and-trade programs, under which overall GHG emissions are limited and GHG emissions are then allocated and sold, and possibly other regulatory requirements, that could result in our incurring material expenses to comply, e.g., by being required to purchase or to surrender allowances for GHGs resulting from our operations. The federal, regional and local regulatory initiatives also could adversely affect the marketability of the oil and natural gas that our clients produce. The impact of such future programs cannot be predicted, but we do not expect our operations to be affected any differently than other similarly situated domestic competitors.

Significant physical effects of climatic change have the potential to damage our facilities, disrupt our production activities and cause us to incur significant costs in preparing for or responding to those effects.

        In an interpretative guidance on climate change disclosures, the SEC indicates that climate change could have an effect on the severity of weather (including hurricanes and floods), sea levels, the arability of farmland, and water availability and quality. If such effects were to occur, our seismic acquisition operations have the potential to be adversely affected. Potential adverse effects could include damages to our facilities from powerful winds or rising waters in low-lying areas, disruption of our production activities either because of climate-related damages to our facilities in our costs of operation potentially arising from such climatic effects, less efficient or non-routine operating practices necessitated by climate effects or increased costs for insurance coverages in the aftermath of such effects. Significant physical effects of climate change could also have an indirect affect on our financing and operations by disrupting the transportation or process-related services provided by midstream companies, service companies or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change.

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Federal legislation and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

        The U.S. Senate and House of Representatives are currently considering bills entitled, the "Fracturing Responsibility and Awareness of Chemicals Act," or the "FRAC Act," that would amend the federal Safe Drinking Water Act, or the "SDWA," to repeal an exemption from regulation for hydraulic fracturing. If enacted, the FRAC Act would amend the definition of "underground injection" in the SDWA to encompass hydraulic fracturing activities. If enacted, such a provision could require hydraulic fracturing operations to meet permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting, and recordkeeping obligations, and meet plugging and abandonment requirements. The FRAC Act also proposes to require the reporting and public disclosure of chemicals used in the fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. The adoption of any future federal or state laws or implementing regulations imposing reporting obligations on, or otherwise limiting, the hydraulic fracturing process could make it more difficult to complete natural gas wells. A significant portion of our anticipated future business involves seismic acquisition projects of various shale plays. Shale gas cannot be economically produced without extensive fracing. In the event this legislation is enacted, demand for our seismic acquisition services may be adversely affected.

Item 1B.    Unresolved Staff Comments

        None.

Item 2.    Properties

        We own or lease administrative offices, operations centers, data processing centers, and warehouses throughout the world. No significant lease is scheduled to terminate in the near future, and we believe comparable space is readily obtainable should any lease expire without renewal. We believe our properties are generally well maintained and adequate for their intended use. As of December 31, 2009, we leased properties worldwide totaling approximately 563,000 square feet. Of this total, 126,000 square feet are located in North America and 437,000 square feet are located internationally.

        Our seismic data processing leased facilities are located in Houston, Texas in the United States, and in Old Woking, Surrey in the United Kingdom.

        Within North America, our seismic data acquisition leased facilities are located in Houston and Midland, Texas; in Cannonsburg, Pennsylvania; and in Calgary, Canada.

        Outside the United States, we lease facilities for our seismic data acquisition segment in Rio de Janeiro, Brazil; Santa Cruz, Bolivia; Bogota and Cundinamarca, Colombia; Quito, Ecuador; Lima, Peru; San Fernando, Trinidad; Brisbane, Australia; Dhaka, Bangladesh; Jakarta, Indonesia; Douala, Cameroon; Cairo, Egypt; Luanda, Soyo, and Viana, Angola; and Abu Dhabi, United Arab Emirates. We own two warehouse facilities in Siberia and Yopal, Colombia totaling approximately 35,000 square feet.

Item 3.    Legal Proceedings

        Neither we nor any of our subsidiaries is a party to any pending legal proceedings other than certain routine litigation that is incidental to our business and that we believe is unlikely to materially impact us. Moreover, we are not aware of any such legal proceedings that are contemplated by governmental authorities with respect to us, any of our subsidiaries, or any of their respective properties that we believe would have a material impact to our financial position or results of operation.

Item 4.    [Removed and Reserved]

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PART II

Item 5.    Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

        Our common stock, $0.01 par value per share, is listed on the NYSE AMEX (formerly the American Stock Exchange) under the trading symbol "GOK." As of December 31, 2009, we had 79 stockholders of record; however, since many shares may be held by investors in nominee names such as the name of their broker or their broker's nominee, the number of record holders often bears little relationship to the number of beneficial owners of the common stock.

        The following table sets forth the high and low closing prices for the common stock of Geokinetics, Inc. during the most recent two fiscal years, as reported by the NYSE AMEX. The following quotations reflect inter-dealer prices, without retail mark-up, mark-down or commission and may not represent actual transactions.

        The closing market price of our common stock on December 31, 2009 was $9.62 per share.

        We have never paid cash dividends on our common stock and the Board of Directors intends to retain all of our earnings, if any, to finance the development and expansion of our business. There can be no assurance that our operations will prove profitable to the extent necessary to pay cash dividends. Moreover, even if such profits are achieved, the future dividend policy will depend upon our earnings, capital requirements, financial condition, debt covenants and other factors considered relevant by our Board of Directors.

Stock Performance Graph

        The information included under the caption "Stock Performance Graph" in this Item 5 of this annual report is not deemed to be "soliciting material" or to be "filed" with the SEC or subject to Regulation 14A or 14C under the Exchange Act or to the liabilities of Section 18 of the Exchange Act, and will not be deemed to be incorporated by reference into any filings we make under the Securities Act of 1933 or the Exchange Act, except to the extent the Company specifically incorporates it by reference into such a filing.

        The following graph depicts the five-year cumulative total return of our common stock as compared with the S&P 500 Stock Index and a peer group made up of companies on the PHLX Oil Services Index (OSX). The PHLX Index consists of larger companies that perform a variety of services as compared to land based acquisition and processing of seismic data performed by us.

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Comparison of 5-year Cumulative Total Return*
Among Geokinetics Inc., the S&P 500 Index and the PHLX Oil Service Sector Index

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*

$100 invested on 12/31/04 in stock or index—including investment of dividends

Securities Authorized for Issuance under Equity Compensation Plans

        As of December 31, 2009, we had two active equity compensation plans approved by security holders: the 2002 Stock Awards Plan and the 2007 Stock Awards Plan. Adopted in March 2003 and amended in November 2006, the 2002 Plan has 800,000 shares of common stock authorized for

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issuance and the 2007 Plan, adopted on May 23, 2007, has 750,000 shares of common stock authorized for issuance.

Item 6.    Selected Financial Data

        The following selected financial data should be read in conjunction with Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations," and with our consolidated financial statements and related notes included in Item 8. "Financial Statements and Supplementary Data."

Selected Financial Data

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(5)

Includes $303.8 million of restricted cash which was used to fund the PGS Onshore Acquisition and repay certain indebtedness in February 2010.

(6)

During 2009, we recorded a $7.2 million provision for uncertain tax positions in a foreign location.

(7)

Loss applicable to common stockholders was impacted by inducements paid of $9.2 million to preferred stockholders in connection with our preferred stock restructuring.

(8)

During 2008, we exchanged our series B-2 preferred stock for series C preferred stock which is classified as mandatorily redeemable preferred stock.

Item 7.    Management's Discussion and Analysis of Financial Condition and Results of Operation

        The following discussion of our financial condition and results of operations should be read in conjunction with the financial statements and notes to those financial statements included elsewhere in this Form 10-K. This discussion contains forward looking statements that involve risks and uncertainties. Please see "Risk Factors" and "Forward Looking Statements" elsewhere in this Form 10-K.

Overview

        We are a full-service, global provider of seismic data acquisition and seismic data processing and interpretation services. We believe that, taking into account the recent PGS Onshore acquisition, we are the second-largest provider of seismic data acquisition services in land, transition zone and shallow water environments based on total worldwide crew count. Our services are used by E&P Companies to identify and analyze drilling prospects, maximize drilling success, optimize field development and enhance production economics.

        Our management consistently monitors and assesses the risk factors and opportunities that may affect us. More specifically, while demand for our services over the past year dropped significantly, we focused on the opportunities in international markets, and on obtaining better terms and conditions on contracts. In addition, we entered into the multi-client data business at the end of 2008.

        We have and will continue to aggressively compete for seismic projects from both existing and prospective customers. In international markets, we have seen increasing demand from state-owned national oil companies ("NOCs") and believe changing global dynamics relative to the oil and gas industry will result in increased opportunities with the NOCs and given our existing relationships, we believe we are well positioned to take advantage of these opportunities.

        We continue to focus on increasing our revenues and profitability by taking the following steps:

•

Updating our technology and increasing our channel count per crew to allow us to compete for larger projects, which typically are more profitable;



•

Standardizing our equipment across our crews to allow us to move from country to country as conditions dictate and reduce crew downtime;



•

Lowering our general and administrative costs as a percentage of revenues by reorganizing management and by increasing operational efficiencies; and



•

Invest in systems to standardize and automate processes.

        Global energy demand growth.    Although demand for energy has recently declined, we believe that long-term, global demand for energy will increase and as that demand rebounds, demand for seismic services from E&P companies will also increase.

        E&P capital spending.    The need to replace depleting reserves should encourage capital expenditures by E&P companies in exploration and production, which we expect will benefit the seismic services industry. We believe that E&P Companies, including many national oil and gas companies,

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remain under pressure to increase or replenish reserves and are looking to unconventional resource plays, transition zones, international locations and the optimization of current reserves with new technology to achieve these results. Seismic data acquisition services are a key component of E&P Companies' capital expenditure programs.

        Technological development.    The application and utilization of seismic services have considerably increased over the last several years as a result of significant technological advancements, such as the move from 2D to 3D and single-component to multi-component seismic data recording and processing. Seismic services can now be applied to the entire sequence of exploration, development and production, as opposed to exploration only, allowing for a greater range of use for our services. In addition, surveys previously shot 2D or single-component are often being reshot with newer techniques to give greater clarity to the subsurface.

        Developments related to our business during 2009 and early 2010 include the following:

•

On December 3, 2009, we entered into an agreement to acquire the global onshore seismic business of Petroleum Geo-Services



•

On December 18, 2009, we issued $294.3 million, net of discount, of Senior Secured Notes Due 2014



•

On December 18, 2009, we issued 4,000,000 shares of common stock for approximately $34.8 million, and restructured our Series B preferred stock,



•

On January 14, 2010, we issued 207,200 shares as part of the overallotment option to the underwriters of the December 18, 2009 stock issuance for approximately $1.8 million.



•

On February 12, 2010, we consummated the acquisition of PGS Onshore, refinanced our senior secured revolving credit facility and paid off substantially all our existing capital lease obligations.

        As of December 31, 2009, our core operating business segments were seismic data acquisition and seismic data processing and interpretation. Our corporate activities include our general and administrative functions.

Recent Acquisitions

        We have completed one large acquisition in the last four years. In addition, on February 12, 2010, we completed the PGS Onshore acquisition.

Grant Acquisition

        On September 8, 2006, we acquired all of the capital stock of Grant Geophysical, Inc., which added international seismic data acquisition services to our business, for $125.0 million in cash. The purchase of Grant was funded from the proceeds of a $55.0 million subordinated loan from Avista and another institutional investor and a $100.0 million senior loan from Royal Bank of Canada, as administrative agent and lender, and Avista in connection with this acquisition. We used approximately $125.0 million for the purchase of Grant, $11.6 million of proceeds from such loans to refinance existing indebtedness, approximately $4.0 million for the payment of fees and expenses incurred in connection with such loans and the remainder for working capital.

The PGS Onshore Acquisition

        On December 3, 2009, we entered into a purchase agreement with Petroleum Geo-Services and its subsidiaries in which we agreed to purchase PGS Onshore for $210.0 million, consisting of $183.9 million of cash and 2,153,616 shares of our common stock, subject to adjustment, primarily for

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changes in working capital. In addition, we agreed to assume approximately $20.7 million of current liabilities associated with the ordinary course operations of PGS Onshore as specified in the purchase agreement. Under the purchase agreement, we agreed to purchase seven corporations or other entities owned by Petroleum Geo-Services or its subsidiaries, and to acquire assets and assume liabilities from four other subsidiaries of Petroleum Geo-Services. The entities and assets acquired represent substantially all of PGS Onshore. We closed the acquisition on February 12, 2010, after obtaining any consents and approvals required under competition laws and satisfaction of customary closing conditions.

        In connection with the acquisition of PGS Onshore, we entered into a new $50 million senior secured revolving credit facility. See the discussion under "Liquidity and Capital Resources" below.

Results of Operations

        Summary of Overall Performance for 2009.    During 2009, we experienced significant revenue growth in international markets and overall offset by significant declines in activity levels in North America, both in data acquisition and processing. The data acquisition segment experienced substantial earnings growth and continued to provide a strong base of earnings and cash flow for us. The data processing and interpretation segment also contributed slightly reduced results. The table below provides further analysis of our operating results and significant highlights by segment/reporting unit/area of operation:

        We spent approximately $38.8 million during 2009 in capital expenditures primarily for new vessels for our shallow water operations, new information systems, investments in surveying and drilling equipment for crews relocating from North America and maintenance capital expenditures.

Results of Operations for Year Ended December 31, 2009 compared to 2008

        Operating Revenues.    Revenues for the twelve months ended December 31, 2009 totaled $511.0 million as compared to $474.6 million for the same period of 2008, an increase of 7.7%. This increase in revenue is attributable primarily to the Company's international seismic data acquisition segment. For the twelve months ended December 31, 2009, seismic data acquisition revenue totaled $500.3 million as compared to $462.6 million for the same period of 2008, an increase of 8.1%. This increase in seismic data acquisition revenue is primarily attributable to investment in additional international crew capacity and continued strong demand for our services in niche markets such as OBC and transition zone. Seismic data acquisition revenues for the twelve months ended December 31, 2009 includes $83.1 million or 16.6% from North America, and $417.1 million or 83.4% from international. Seismic data processing revenue totaled $10.7 million for the year ended December 31, 2009 as compared to $12.0 million for the same period of 2008, a decrease of 11% due to decreased

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demand and increased price competition. Revenues include data library licensing revenues of $10.3 million and $0.5 million for the years ended December 31, 2009 and 2008.

        Operating Expenses.    Operating expenses for the twelve months ended December 31, 2009 totaled $370.2 million as compared to $370.2 million for the same period of 2008. Of the total operating expenses, seismic data acquisition operating expenses totaled $361.6 million for the twelve months ended December 31, 2009, as compared to $361.3 million for the same period of 2008. While seismic data acquisition revenues increased by 7.7%, data acquisition operating expenses remained the same due to the shift in job mix towards higher margin, international programs. Seismic data acquisition operating expenses for the twelve months ended December 31, 2009 includes $66.0 million, or 18.2%, from North America, and $295.6 million, or 81.8% from International. Seismic data processing operating expenses totaled $8.6 million for the year ended December 31, 2009, as compared to $8.9 million for the same period of 2008, a decrease of 3.4% primarily due to lower activity levels.

        General and Administrative Expenses.    General and administrative expenses for the twelve months ended December 31, 2009 were $53.8 million as compared to $39.3 million for the same period of 2008, an increase of $14.5 million or 36.9%. This increase is primarily the result of salary expenses associated with increased personnel levels due to our overall growth; the strengthening of our infrastructure consisting primarily of information systems implementation costs, severance costs, and costs incurred related to the PGS Onshore acquisition.

        Depreciation and Amortization Expenses.    Depreciation and amortization expense for the twelve months ended December 31, 2009 totaled $56.9 million as compared to $49.0 million for the same period of 2008, an increase of $7.9 million or 16.1%. This is primarily attributable to continued capital expenditures to support international crews along with the amortization of the multi-client investment. We incurred capital expenditures of $38.8 million in 2009 as compared to $77.1 million in 2008. Amortization of multi-client data for the years ended December 31, 2009 and 2008, was $6.6 million and $0.5 million, respectively.

        Interest Expense.    Interest expense (net of interest income) for the twelve months ended December 31, 2009 increased by $2.7 million or 43.5% to $8.9 million as compared to approximately $6.2 million for the same period of 2008. This increase is primarily due to a $2.9 million charge for a bridge commitment we obtained in connection with the signing of the purchase agreement to purchase PGS Onshore.

        Income Tax.    Provision for income taxes for the twelve months ended December 31, 2009 was $23.3 million, as compared to $9.3 million for the same period of 2008, an increase of $14.0 million or 150.5%. The increase is mainly due to increased profitability in foreign jurisdictions and related withholding taxes. The increase is mainly due to increased profitability in foreign jurisdictions, increased activity in deemed profit areas where taxes are calculated as a percentage of revenues and increased withholding taxes on the rental of our United States owned equipment to our foreign subsidiaries. In addition, the Company recorded a $7.2 million charge during 2009 for an uncertain tax position in one of its foreign operations

        EBITDA and Net Loss.    EBITDA (as defined below) increased 33.8% to $87.0 million for 2009 compared to $65.0 million for 2008. This increase was due to increased international revenues and improved international margins, primarily as a result of a higher contribution from shallow water OBC and transition zone projects. We also had better crew utilization and less down time due to longer term contracts. We had a loss applicable to common stockholders of $22.4 million, or ($2.06) per share, for the twelve months ended December 31, 2009, as compared to a loss applicable to common stockholders of $5.3 million, or ($0.51) per share, for the twelve months ended December 31, 2008. The increase in our net loss applicable to stockholders is primarily due to $13.3 million of one-time inducement

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payments to preferred shareholders, bridge loan fee, and acquisition costs related to the PGS Onshore acquisition.

        We define EBITDA as net income (loss) (the most directly generally accepted accounting principle or "GAAP" financial measure) before Interest, Taxes, Other Income (Expense) (including foreign exchange gains/losses, gains/losses on sale of equipment and insurance proceeds, warrant expense and other income/expense), and Depreciation and Amortization. "EBITDA," as used and defined by us, may not be comparable to similarly titled measures employed by other companies and is not a measure of performance calculated in accordance with GAAP. EBITDA should not be considered in isolation or as a substitute for operating income, net income or loss, cash flows provided by operating, investing and financing activities, or other income or cash flow statement data prepared in accordance with GAAP. However, we believe EBITDA is useful to an investor in evaluating our operating performance because this measure: (1) is widely used by investors in the energy industry to measure a company's operating performance without regard to items excluded from the calculation of such term, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and the method by which assets were acquired, among other factors; (2) helps investors to more meaningfully evaluate and compare the results of our operations from period to period by removing the effect of our capital structure and asset base from its operating structure; and (3) is used by our management for various purposes, including as a measure of operating performance, in presentations to our board of directors, as a basis for strategic planning and forecasting, and as a component for setting incentive compensation. There are significant limitations to using EBITDA as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect our net income or loss, and the lack of comparability of results of operations of different companies.

        See below for reconciliation from net income to common stockholders to EBITDA:

        Update of Credit Metrics.    In 2009, our credit metrics were significantly impacted as a result of several actions taken during the course of the year including:

•

Increased revenues and EBITDA



•

Significant changes in capital structure in preparation for the PGS Onshore acquisition



•

Sale of 4,000,000 shares of common stock



•

$300 million Senior Secured Notes

        These actions taken during 2009 successfully positioned us for the PGS Onshore acquisition and to provide financial flexibility for future, focused growth.

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Results of Operations for Year Ended December 31, 2008 compared to 2007

        Operating Revenues.    Revenues for the twelve months ended December 31, 2008 totaled $474.6 million as compared to $357.7 million for the same period of 2007, an increase of 33%. This increase in revenue is attributable primarily to our seismic data acquisition segment. For the twelve months ended December 31, 2008, seismic data acquisition revenue totaled $462.6 million as compared to $346.8 million for the same period of 2007, an increase of 33%. This increase in seismic data acquisition revenue is primarily attributable to improved contract terms, investment in additional crew capacity and continued strong demand for our services. Seismic data acquisition revenues for the twelve months ended December 31, 2008 includes $177.5 million or 38% from North America, and $285.1 million or 62% from international. Seismic data processing revenue totaled $12.0 million at December 31, 2008 as compared to $10.8 million for the same period of 2007, an increase of 11% due to increased demand for processing of seismic data combined with increased marketing efforts.

        Operating Expenses.    Operating expenses for the twelve months ended December 31, 2008 totaled $370.2 million as compared to $290.8 million for the same period of 2007, an increase of 27%. This increase in operating expenses is primarily attributable to our seismic data acquisition segment. Seismic data acquisition operating expenses totaled $361.3 million for the twelve months ended December 31, 2008, as compared to $280.2 million for the same period of 2007, an increase of 29%. Increased operating expenses at our seismic data acquisition segment are primarily the result of increased seismic data acquisition activity. Seismic data acquisition operating expenses for the twelve months ended December 31, 2008 includes $138.2 million, or 38%, from North America, and $223.1 million, or 62% from International. Seismic data processing operating expenses totaled $8.9 million for the twelve months ended December 31, 2008, as compared to $10.6 million for the same period of 2007, a decrease of 16% primarily due to cost reduction efforts implemented in late 2007 and improved productivity of existing resources.

        General and Administrative Expenses.    General and administrative expenses for the twelve months ended December 31, 2008 were $39.3 million as compared to $35.7 million for the same period of 2007, an increase of $3.6 million or 10%. This increase is primarily the result of salary expenses associated with increased personnel levels due to our overall growth; information systems implementation costs and increased bonus accruals due to higher activity levels under our incentive plans.

        Depreciation and Amortization Expenses.    Depreciation and amortization expense for the twelve months ended December 31, 2008 totaled $49.0 million as compared to $32.4 million for the same period of 2007, an increase of $16.6 million or 51%. This is primarily attributable to depreciation expense associated with high levels of capital expenditures in the second half of 2007 and all of 2008. We incurred capital expenditures of $77.1 million in 2008 as compared to $94.7 million in 2007. Our capital expenditures in 2008 included additional recording capacity internationally, expansion of our shallow water operations and investments in new information systems.

        Interest Expense.    Interest expense (net of interest income) for the twelve months ended December 31, 2008 decreased by $9.0 million or 59% to $6.2 million as compared to approximately $15.2 million for the same period of 2007. This decrease is primarily due to the elimination of interest incurred on our floating rate notes, which were issued in December 2006 and redeemed in June 2007. In addition, we recorded a $6.9 million loss on the redemption of the floating rate notes which consisted of a $3.3 million premium and recognition of $3.6 million of unamortized finance costs in 2007.

        Income Tax.    Provision for income taxes for the twelve months ended December 31, 2008 was $9.3 million, as compared to $2.3 million for the same period of 2007, an increase of $6.9 million or 300%. The increase is mainly due to increased profitability in foreign jurisdictions and related withholding taxes and decreased profitability in the U.S.

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        EBITDA and Net Loss.    EBITDA increased to $65.0 million for 2008 compared to $31.2 million for 2007. We had a loss applicable to common stockholders of $5.3 million, or ($0.51) per share, for the twelve months ended December 31, 2008, as compared to loss applicable to common stockholders of $20.8 million, or ($2.44) per share, for the same period of 2007. The decrease in our loss applicable to common stockholders of $15.5 million is primarily due to decreased interest expense, loss on the redemption of the Notes and one-time severance and reorganization costs in 2007 and improved operations in 2008.

        See below for reconciliation from net loss applicable to common stockholders to EBITDA :

Inflation and Price Changes

        We do not believe that inflation has had a significant effect on our business, financial condition, or results of operations during the most recent three years.

Foreign Currency Exchange Risk

        We operate in certain countries where we are exposed to foreign currency exchange risk. As the majority of our contracts are denominated in U.S. dollars, when possible, we mitigate this risk by entering into split-dollar contracts. Under a split-dollar contract, each client invoice is split into a local currency payment and a U.S. dollar payment. The local currency payment is collected locally and used to fund local expenditures, while the U.S. dollar payment is made directly to a U.S. dollar denominated bank account. This reduces our exposure to foreign currency risks.

Liquidity and Capital Resources

        Our primary sources of cash have been cash flow generated by our seismic data acquisition and seismic data processing segments, debt and equity transactions, equipment financing and trade credit. Our primary uses of cash have been for operating expenses associated with our seismic data acquisition and seismic data processing segments, capital expenditures associated with upgrading and expanding our capital asset base and debt service.

        As of December 31, 2009, we had available liquidity as follows:

Total borrowing capacity under revolving credit facility: $58.1 million
Available cash: $10.2 million
Undrawn borrowing capacity under revolving credit facility: $5.9 million
Net available liquidity at December 31, 2009: $16.1 million

        As of December 31, 2009, we also had approximately $305.8 million in restricted cash primarily to repay our existing revolving credit facility and substantially all of our capital lease obligations and to pay the cash portion of the PGS Onshore acquisition.

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        We have certain foreign overdraft facilities in the amount of $6.3 million which were undrawn at December 31, 2009. However, due to limitations on the ability to remit funds to the United States, these have been excluded in the available liquidity table above.

        The table below summarizes certain measures of liquidity and capital expenditures, as well as our sources of capital from internal and external sources, for the past three years.

        Net cash provided by operating activities was $53.3 million for the twelve months ended December 31, 2009 compared to net cash provided by operating activities of $37.6 million for the twelve months ended December 31, 2008. These amounts result from our operating results adjusted by changes in working capital and depreciation. The increase in net cash provided by operating activities was primarily the result of higher activity levels and improved operating results.

        Net cash used in investing activities was $349.0 million for the twelve months ended December 31, 2009 and $43.3 million for the twelve months ended December 31, 2008. The increase in cash used in investing activities is primarily due to approximately $303.8 million which was deposited into escrow accounts for the PGS Onshore acquisition. Other amounts primarily represent capital expenditures and investment in multi-client data library made during the respective twelve month period. During the twelve months ended December 31, 2009 we also had reduced purchases of seismic data acquisition equipment from 2008.

        Net cash provided by financing activities was $292.6 million for the twelve months ended December 31, 2009 as compared to net cash provided by financing activities of $4.0 million for the twelve months ended December 31, 2008. These totals represent the net proceeds and net payments from our debt and equity transactions.

Preferred Stock

        In December 2006, we issued series B-1 preferred stock to affiliates of Avista Capital Partners L.P. and another institutional investor, and in July 2008, we issued shares of series B-2 preferred stock and warrants to purchase 240,000 shares of our common stock to Avista. In connection with the PGS Onshore acquisition and the common stock offering, on December 18, 2009, we restructured the series B-1 preferred stock to reduce the conversion price from $25 to $17.436, to increase the dividend of the series B-1 preferred stock to 9.75%, to extend the dates on which we may pay interest in kind and after which we are required to redeem the series B-1 preferred stock until one year after the maturity date of the notes, and to waive certain other provisions of the series B-1 preferred stock to facilitate the acquisition. We agreed to pay Avista Capital Holdings, L.P. and Levant America S.A. a fee of $1.5 million, which was 2% of the liquidation amount of the preferred stock.

        Additionally, we agreed to exchange the series B-2 preferred stock for a new series of preferred stock, Series C, plus the issuance of 750,000 shares of our common stock and a fee of $0.6 million, which was 2% of the liquidation value of the preferred stock. The new preferred stock is not convertible, and has a dividend rate of 11.75% and an aggregate liquidation amount of $32.8 million. We will have the ability to pay dividends on the new preferred stock in kind or allow them to accrue

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without being paid, and will not be required to redeem the new preferred stock for the liquidation amount, until one year after the maturity of the Notes, December 15, 2015. The new series of preferred stock will be considered a mandatorily redeemable financial instrument that is within the scope of ASC 480, "Distinguishing liabilities from equity" and therefore will be classified a long-term liability. The dividends payable on the new series of preferred stock will be classified as interest expense.

Senior Secured Notes Due 2014

        On December 23, 2009, one of our wholly owned subsidiaries, Geokinetics Holdings, USA, Inc., issued $300 million senior secured notes due 2014 (the "Notes") in a private placement to institutional buyers at an issue price of 98.093% of the principal amount or approximately $294.3 million.

        The Notes bear interest at the rate of 9.75% per year, payable semi-annually in arrears on June 15 and December 15 of each year, with interest payments commencing in June 2010. The Notes are fully and unconditionally guaranteed, jointly and severally, by us, and by each of our current and future domestic subsidiaries.

        Until the second anniversary following their issuance, we may redeem up to 10% of the original principal amount of the Notes during each 12-month period at 103% of the principal amount plus accrued interest. Thereafter, we may redeem all or part of the notes at a prepayment premium which will decline over time. We will be required to make an offer to repurchase the notes at 101% of the principal amount plus accrued interest if we experience a change of control. The indenture for the notes contains customary covenants for non-investment grade indebtedness, including restrictions on our ability to incur indebtedness, to declare or pay dividends and repurchase our capital stock, to invest the proceeds of asset sales, and to engage in transactions with affiliates.

        As required by the Notes indenture, at closing, we deposited into escrow $303.8 million, which was 101% of the aggregate issue price of the Notes, plus an amount necessary to pay the interest on the Notes from and including the issue date of the Notes to, but excluding, March 15, 2010. The holders of the Notes had a first priority lien on the amounts in the escrow account. This amount was in escrow on December 31, 2009 and was released in connection with the closing of the PGS Onshore acquisition on February 12, 2010. We used a portion of the amounts released from escrow to pay the cash portion of the purchase price of the PGS Onshore acquisition, repay existing indebtedness and to pay related expenses.

Revolving Credit Facilities

        PNC Credit Facility.    On June 12, 2006, we and four of our subsidiaries (collectively, the "Borrowers") completed the closing of a credit facility under the terms of a Revolving Credit, Term Loan and Security Agreement (collectively, the "Credit Agreement") dated as of June 8, 2006 with PNC Bank, National Association ("PNC"), as lender. We pledged our assets as security to PNC. The Credit Agreement contains certain restrictive covenants limiting our ability to incur additional debt and purchase additional assets. This Credit Agreement has been amended several times to among other things increase the revolving credit and expenditures facilities.

        The amount available to borrow under the revolver is dependent upon the calculation of a monthly borrowing base that is composed of eligible accounts receivables and eligible fixed assets. The borrowing base can fluctuate from time to time due to fluctuations in accounts receivable balances. Additionally, a portion of the borrowing base is composed of eligible fixed assets.

        We further amended the Credit Agreement with PNC on February 11, 2009. Among other things, the amended agreement increased our borrowing base that can come from eligible fixed assets to $55.0 million and deferred any reductions to this new amount until June 30, 2009, at which time, the amount of the borrowing base that can come from eligible fixed assets started to be reduced by

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$0.9 million per month until maturity. This reduction only affected the amount of the borrowing base that can come from eligible fixed assets and did not reduce the overall amount of the revolver.

        Based on our borrowing base at December 31, 2009, we had available credit under this facility of $58.1 million reduced by standby letters of credit totaling $2.3 million issued by PNC under the revolver. At December 31, 2009, we had a balance of $44.6 million drawn under the revolver. The outstanding amount under this facility on February 12, 2010 was fully repaid as this facility was replaced with a new revolving credit facility with the Royal Bank of Canada ("RBC") on that date.

        RBC Credit Facility.    On December 2, 2009, we received a commitment from RBC to provide a new $50.0 million senior secured revolving credit facility and we closed on this new facility on February 12, 2010. The revolving credit facility will mature on February 12, 2013, three years after the closing of the PGS Onshore acquisition. We may borrow, repay and re-borrow under the revolving credit facility at any time following February 12, 2010, until the maturity date of the facility. Borrowings outstanding under the revolving credit facility will bear interest at a floating rate based on the greater of: i) 3% per year, ii) Prime Rate, iii) 0.5% above the Federal Funds Rate, or iv) 1% above one month LIBOR; plus an applicable margin between 4.25% and 5.25% until June 29, 2010. Beginning June 30, 2010, the applicable margin will range between 3.5% and 5.5% depending on our total leverage ratio..

        Borrowings under the revolving credit facility are unconditionally guaranteed by Geokinetics and each of its existing and each subsequently acquired or organized wholly-owned U.S. direct or indirect material subsidiary of Geokinetics. Each of the entities guaranteeing the revolving credit facility will secure the guarantees on a first priority basis with a lien on substantially all of the assets of such guarantor. Borrowings under the revolving credit facility are deemed Priority Bank Debt under the inter-creditor agreement with the holders of the Notes, and so the Notes will be effectively subordinated to borrowings under the revolving credit facility pursuant to such inter-creditor agreement.

Capital Lease Obligations

        We have several equipment lease agreements with CIT Group Equipment Financing, Inc. ("CIT") for seismic and other transportation equipment with terms of up to 36 months and various interest amounts. The original amount of the leases was approximately $39.9 million and the balance at December 31, 2009 was approximately $12.1 million. These amounts were repaid on February 12, 2010 in connection with the closing of the PGS Onshore acquisition, and therefore, have been classified as short-term at December 31, 2009.

        We also have four equipment lease agreements with Bradesco Leasing in Brazil with terms of 36 months at a rate of 9.6% per year. The original amount of the leases was approximately $3.0 million and the balance at December 31, 2009 was approximately $2.7 million.

Other

        From time to time, we enter into vendor financing arrangements to purchase certain equipment. The equipment purchased from these vendors is paid over a period of time. The total balance of vendor financing arrangements at December 31, 2009 was approximately $9.9 million. These amounts were repaid on February 12, 2010 in connection with the closing of the PGS Onshore acquisition, and therefore, have been classified as short-term at December 31, 2009.

        In conjunction with the acquisition of PGS, we received a commitment from RBC to make a bridge loan in the amount of $275.0 million. The proceeds from this loan would have been used to finance the PGS Onshore acquisition and repay our existing indebtedness if the Senior Secured Notes offering was not completed. We paid a commitment fee for the bridge loan of approximately

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$2.9 million. The bridge loan commitment terminated upon the completion of the PGS Onshore acquisition.

        We have made, and expect to continue to make, significant investments in capital expenditures. In 2009, we incurred $38.8 million in capital expenditures. We expect to update our capital expenditure budget to include PGS Onshore in the coming months.

        Our Board of Directors has approved a capital expenditure budget for 2010 of $65.3 million, which is an increase of 57% from capital expenditures in 2009. We expect investments in 2010 to be primarily targeted toward expansion of our shallow water capabilities, expansion of our international operations and maintenance capital expenditures.

        In addition, our Board of Directors has approved multi-client data library investments for 2010 of $47.0 million to date subject to certain minimum pre-funding levels. This amount does not include any amounts for multi-client data library investments related to PGS Onshore or other surveys in progress of being developed which will be approved at a later date. We expect our investments in 2010 to be primarily focused on the expansion of our existing multi-client data library interests in the Marcellus Shale in Pennsylvania.

        We believe that our current cash balances and anticipated cash flow from our seismic data acquisition and seismic data processing operations, combined with available debt financing, will provide sufficient liquidity to continue operations throughout 2010. Should our current sources of liquidity not meet our operating requirements, we would be forced to seek outside sources of capital to meet our operating and capital requirements and/or curtail our capital expenditure program.

Critical Accounting Policies

        A critical accounting policy is one that is both important to the presentation of our financial condition and results of operations and requires management to make difficult, subjective or complex accounting estimates. An accounting estimate is an approximation made by management of a financial statement element, item or account in the financial statements. Accounting estimates in our historical consolidated financial statements measure the effects of past business transactions or events, or the present status of an asset or liability. The accounting estimates described below require us to make assumptions about matters that are highly uncertain at the time the estimate is made. Additionally, different estimates that we could have used or changes in an accounting estimate that are reasonably likely to occur could have a material impact on the presentation of our financial condition or results of operations. The circumstances that make these judgments difficult, subjective and/or complex have to do with the need to make estimates about the effect of matters that are inherently uncertain. Estimates and assumptions about future events and their effects cannot be predicted with certainty. We base our estimates on historical experience and on various other assumptions that we believe to be reasonable under the circumstances, the results of which form the basis for making judgments. These estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes. Our significant accounting policies are discussed in Note 2 to our consolidated financial statements. We believe the following accounting policies involve the application of critical accounting estimates.

Use of Estimates in Preparing Consolidated Financial Statements

        We use estimates and assumptions in preparing consolidated financial statements in accordance with accounting principles generally accepted in the U.S. Those estimates and assumptions are included in our consolidated financial statements and accompanying notes. The more significant areas requiring the use of our estimates relate to accounting for contracts in process, evaluating the outcome of uncertainties involving claims against or on our behalf , determining useful lives for depreciation and amortization purposes, cash flow projections and fair values used in the determination of asset

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impairment. While we believe current estimates are reasonable and appropriate, actual results could differ materially from current estimates.

Fair Values of Financial Instruments

        Effective January 1, 2008, we adopted ASC Topic 820 as it relates to financial assets and financial liabilities, which defines fair value, establishes a framework for measuring fair value under generally accepted accounting principals and expands disclosures about fair value measurements. The provisions of this standard apply to other accounting pronouncements that require or permit fair value measurements.

        This guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Hierarchical levels, as defined in this guidance and directly related to the amount of subjectivity associated with the inputs to fair valuations of these assets and liabilities, are as follows:

        Level 1—Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities.

        Level 2—Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly, including quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; inputs other than quoted prices that are observable for the asset or liability (e.g., interest rates); and inputs that are derived principally from or corroborated by observable market data by correlation or other means.

        Level 3—Inputs that are both significant to the fair value measurement and unobservable.

        The reported fair values for financial instruments that use Level 2 and Level 3 inputs to determine fair value are based on a variety of factors and assumptions. Accordingly, certain fair values may not represent actual values of our financial instruments that could have been realized as of December 31, 2009 or that will be realized in the future and do not include expenses that could be incurred in an actual sale or settlement. The carrying amounts of cash and cash equivalents, accounts receivable, and accounts payable and short-term debt approximate their fair value due to the short maturity of those instruments. We believe the fair value of our long-term debt at December 31, 2009, based on Level 1 measurement, and series B and series C preferred stock, based on Level 2 measurement, to be approximately $400.0 million, $69.3 million, and $32.1 million, respectively.

        We are not a party to any hedge arrangements, commodity swap agreement or other derivative financial instruments. Our seismic data acquisition and seismic data processing segments utilize foreign subsidiaries and branches to conduct operations outside of the United States. These operations expose us to market risks from changes in foreign exchange rates.

Revenue Recognition

        Our services are provided under cancelable service contracts. Customer contracts for services vary in terms and conditions. Contracts are either "turnkey" or "term" agreements or a combination of the two. Under turnkey agreements or the turnkey portions thereof, we recognize revenue based upon output measures as work is performed. This method requires that we recognize revenue based upon quantifiable measures of progress, such as square miles or linear kilometers acquired. With respect to those contracts where the customer pays separately for the mobilization of equipment, we recognize such mobilization fees as revenue during the performance of the seismic data acquisition, using the same performance method as for the acquisition work. We also receive revenue for certain third party charges under the terms of the service contracts. We record amounts billed to customers in revenue as the gross amount including third party charges, if applicable, that are paid by the customer. Our

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turnkey or term contracts generally do not contain cancellation provisions that would prevent us from being compensated for work performed prior to cancellation due to milestones not being met or work not being performed within a particular timeframe. In some instances, customers are billed in advance of work performed and we recognize the advance billing as deferred revenue.

        We account for multi-client data sales as follows:

        (a)   Pre-funding arrangements—We obtain funding from a limited number of customers before a seismic project is completed. In return for the pre-funding, the customer typically gains the ability to direct or influence the project specifications, to access data as it is being acquired and to pay discounted prices. We recognize pre-funding revenue as the services are performed on a proportional performance basis usually determined by comparing the completed square miles of a seismic survey to the survey size unless specific facts and circumstances warrant another measure. Progress is measured in a manner generally consistent with the physical progress on the project, and revenue is recognized based on the ratio of the project's progress to date, provided that all other revenue recognition criteria are satisfied.

        (b)   Late sales—When we grant a license to a customer, the customer is entitled to have access to a specifically defined portion of the multi-client data library. Our customer's license payment is fixed and determinable and typically is required at the time that the license is granted. We recognize revenue for late sales when our customer executes a valid license agreement and has received the underlying data or has the right to access the licensed portion of the data and collection is reasonably assured.

        (c)   Sales of data jointly owned by us and partner—We have jointly acquired surveys with a partner whereby we share the costs of acquisition and earn license revenues when processed data is delivered by our partner to the ultimate client. As such, these revenues are recognized when the processed data is delivered to the ultimate client.

        As a result of the nature of our services, we from time to time engage with customers in renegotiations or revisions of service contracts, which represent contingent revenues that are recognized only when the amounts have been received or awarded.

        Deferred revenue consists primarily of customer payments made in advance of work done, milestone billings and mobilization revenue, amortized over the term of the related contract.

Property and Equipment

        Property and equipment are recorded at cost. Costs related to the development of internal use software and software developed for license for our customers are capitalized and amortized over the estimated useful life of the software. Depreciation and amortization are provided using the straight-line method over the estimated useful lives of the respective assets or the lesser of the lease term, as applicable. Repairs and maintenance, which are not considered betterments and do not extend the useful life of property, are charged to expense as incurred. When property and equipment are retired or otherwise disposed of, the asset and accumulated depreciation or amortization are removed from the accounts and the resulting gain or loss is reflected in operations.

        We review long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability is measured by a comparison of the carrying amount of an asset to future net cash flows expected to be generated by the asset. If such assets are considered to be impaired, the impairment recognized is measured by the amount by which the carrying amount of the assets exceeds either the fair value or the estimated discounted cash flows of the assets, whichever is more readily measurable. At December 31, 2009 and 2008, we deemed no such assets were impaired.

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Goodwill and Intangible Assets

        Goodwill represents the excess of the purchase price over the estimated fair value of the assets acquired net of the fair value of liabilities assumed. Overall accounting for Goodwill Topic 350-20-35 of the FASB Accounting Standards Codification requires intangible assets with indefinite lives, including goodwill, be evaluated on an annual basis for impairment or more frequently if an event occurs or circumstances change which could potentially result in an impairment.

        The impairment test requires the allocation of goodwill and all other assets and liabilities to reporting units. If the fair value of the reporting unit is less than the book value (including goodwill), then goodwill is reduced to its implied fair value and the amount of any write-down is reflected in operations. All of our goodwill is related to our data acquisition segment. While this segment consists of various geographical markets, we have concluded that it has only one reporting unit for purposes of the impairment test. We perform impairment tests on the carrying value of our goodwill on an annual basis as of December 31st. Historically, we have used the Income Approach or the Discounted Cash Flow Method, which focuses on expected cash flows. In applying this approach, the expected cash flow is projected based on assumptions regarding revenues, direct costs, general and administrative expenses, depreciation, applicable income taxes , capital expenditures and working capital requirements for a finite period of years, which was five years in our test. The projected cash flows and the terminal value, which is an estimate of the value at the end of the finite period and assumes a long-term growth rate, are then discounted to present value to derive an indication of the value of the reporting unit. For our annual assessment as of December 31, 2009, due to the economic conditions affecting the industry, we also utilized the Subject Company Valuation Method, which makes a comparison of our projections to reasonably similar publicly traded companies. In weighting the results of the various valuation approaches, we placed more emphasis on the income approach. For the years ended December 31, 2008 and 2009, our annual impairment test indicated the fair value of its reporting unit's goodwill exceeded the carrying amount.

        Intangible assets that do not have indefinite lives are amortized over their estimated useful lives and also reviewed for impairment at least annually. No impairment was deemed necessary.

Multi-client Data Library

        We capitalize all costs directly associated with acquiring and processing the data, including the depreciation of the assets used during production of the surveys. We refer to these costs as our gross multi-client investment. The capitalized cost of the multi-client data is charged to depreciation and amortization in the period the sales occur based on the greater of the percentage of total estimated costs to the total estimated sales in the first five years multiplied by actual sales, known as the sales forecast method, or the straight-line amortization method over five years. This minimum straight-line amortization is recorded only if minimum amortization exceeds the cost of services calculated using the sales forecast method.

        We periodically review the carrying value of the multi-client data library to assess whether there has been a permanent impairment of value and records losses when it is determined that estimated future sales would not be sufficient to cover the carrying value of the asset.

Income Taxes

        We account for income taxes in accordance with FASB Accounting Standards Codification ("ASC") Topic 740. Under this method, deferred tax assets and liabilities are computed using the liability method based on the differences between the financial statement and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse.

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        A valuation allowance is provided, if necessary, to reserve the amount of net operating loss and tax credit carryforwards which we may not be able to use as a result of the expiration of maximum carryover periods allowed under applicable tax codes.

        We apply a more likely than not threshold to the recognition and de-recognition of uncertain tax positions. We recognize the amount of unrecognized tax benefit that has a greater than 50 percent likelihood of being ultimately realized upon settlement. A change in judgment related to the expected ultimate resolution of uncertain tax positions is recognized in earnings in the quarter of such changes.

Recent Accounting Pronouncements

        In May 2009, the Financial Accounting Standards Board (FASB) issued ASC Topic 855, "Subsequent Events." This topic defines subsequent events as events or transactions that occur after the balance sheet date, but before the financial statements are issued. It defines two types of subsequent events: recognized subsequent events, which provide additional evidence about conditions that existed at the balance sheet date, and non-recognized subsequent events, which provide evidence about conditions that did not exist at the balance sheet date, but arose before the financial statements were issued. Recognized subsequent events are required to be recognized in the financial statements, and non-recognized subsequent events are required to be disclosed. ASC Topic 855 requires entities to disclose the date through which subsequent events have been evaluated, and the basis for that date. ASC Topic 855 is consistent with current practice and did not have any impact on our results of operations, financial condition or liquidity.

        In June 2009, the FASB issued ASC Topic 105, "The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles." The statement makes the FASB Accounting Standards Codification (the Codification) the single source of authoritative U.S. accounting and reporting standards, but it does not change U.S. GAAP. The ASC Topic 105 is effective for interim and annual periods ending after September 15, 2009. We have adopted ASC Topic 105 and the financial statements for the year ended December 31, 2009 reflect the Codification references. The statement had no impact on our results of operations, financial condition or liquidity.

Contractual Obligations

        The following table summarizes our obligations and commitments to make future payments of principal and interest under its long-term debt, capital leases and operating leases for the periods specified as of December 31, 2009 (in thousands).

Contractual Obligations Table

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